Bp PLC 6-K, filed Oct 30, 2026
Bp PLC (BP)
6-K
2026-10-30
For: 2026-10-30
View Original
Added on
October 30, 2026
About this 6-K
Bp PLC filed this 6-K on October 30, 2026.
BP p.l.c. reported 3Q 2026 underlying RC profit of $8.5 billion, operating cash flow of $14.8 billion and an $8.4 billion net debt reduction to $13.9 billion. AI summary
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 6-K
Report of Foreign Issuer
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934
30
October, 2026
BP p.l.c.
(Translation
of registrant's name into English)
1 ST JAMES'S SQUARE, LONDON, SW1Y 4PD, ENGLAND
(Address
of principal executive offices)
Indicate
by check mark whether the registrant files or will file
annual
reports
under cover Form 20-F or Form 40-F.
Form
20-F |X| Form 40-F
---------------
----------------
Indicate
by check mark whether the registrant by furnishing the
information
contained
in this Form is also thereby furnishing the information to
the
Commission
pursuant to Rule 12g3-2(b) under the Securities Exchange Act
of
1934.
Yes No
|X|
---------------
--------------
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Exhibit
1.1
|
3Q26 BP
PLC Part 1 of 1 dated 30 October 2026
|
Exhibit 1.1
|
FOR IMMEDIATE RELEAS
|
 |
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London 30 October 2026
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BP p.l.c. Group results
|
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Third quarter and nine months 2026
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|
|
|
|
|
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Cash generation accelerates balance sheet
strengthening
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|
Financial summary
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Profit for the period attributable to bp shareholders
|
|
4,696
|
3,911
|
1,161
|
|
12,449
|
3,477
|
|
Inventory holding (gains) losses*, net of tax
|
|
(1,598)
|
717
|
62
|
|
(4,061)
|
351
|
|
Replacement cost (RC) profit*
|
|
3,098
|
4,628
|
1,223
|
|
8,388
|
3,828
|
|
Net adverse impact of adjusting items*, net of tax
|
|
5,360
|
1,104
|
987
|
|
9,000
|
2,116
|
|
Underlying RC profit*
|
|
8,458
|
5,732
|
2,210
|
|
17,388
|
5,944
|
|
Operating cash flow
|
|
14,829
|
10,858
|
7,786
|
|
28,547
|
16,891
|
|
Capital expenditure
|
|
(3,036)
|
(3,086)
|
(3,381)
|
|
(9,412)
|
(10,365)
|
|
Divestment
and other proceeds(a)
|
|
(21
|
609
|
28
|
|
836
|
1,712
|
|
Net
debt*(b)
|
|
13,870
|
22,251
|
26,054
|
|
13,870
|
26,054
|
|
Underlying
operating expenditure*
|
|
5,264
|
5,333
|
5,487
|
|
15,966
|
16,248
|
|
Announced dividend per ordinary share (cents per
share)
|
|
8.660
|
8.660
|
8.320
|
|
25.640
|
24.640
|
|
Underlying RC profit per ordinary share* (cents)
|
|
54.37
|
36.92
|
14.24
|
|
112.06
|
37.98
|
|
Underlying RC profit per ADS* (dollars)
|
|
3.26
|
2.22
|
0.85
|
|
6.72
|
2.28
|
Key headlines
●
Earnings improve,
supported by the macro environment. 3Q 2026 underlying RC
profit $8.5 billion, $2.7 billion higher than the prior quarter.
Operating cash flow $14.8 billion, including adjusted working
capital* release(c) of $0.5
billion
●
Improved
operational performance. 3Q 2026 upstream plant reliability
95.3% (2Q 2026 92.4%); reported production 2.2mmboe/d (2Q 2026
2.2mmboe/d); refining availability 96.5% (2Q 2026 94.7%); refining
throughput 1,396mb/d (2Q 2026 1,467mb/d) reflects the divestment of
Gelsenkirchen refinery.
●
Strengthening the
balance sheet. Strong cash generation combined with decision
to allocate excess cash to strengthen the balance sheet enabled an
$8.4 billion reduction in net debt to $13.9 billion.
●
Strategy and
outlook update on 15 December. We will set out the next
phase of our plans to build a simpler, stronger and more valuable
bp.
Meg O’Neill, Chief executive officer
“These are dynamic times with volatility and disruption to
trade flows continuing to define energy markets.
The industry as a whole has been showing remarkable adaptability.
Refineries have been running close to capacity to make up for
shortfalls, shipping has been taking different and longer routes,
and releases from strategic and commercial reserves are helping to
bridge supply gaps.
I’m proud of the contribution bp is making to keep energy
flowing. As a global integrated oil and gas company, our
connectivity from the reservoir to the fuel pump is a significant
source of strength and resilience, particularly given our ability
to connect supply with demand.
We maintained upstream production at around 2.2 million barrels per
day, upstream plant reliability and refining availability both
improved compared to the previous quarter, and our trading
performance was also higher.
This has generated a strong set of results, supported by the
higher-price, higher-margin environment and some good progress on
performance improvement across the business. Our underlying
replacement cost profit for the quarter was $8.5 billion and
operating cash flow was $14.8 billion, contributing to a reduction
of $8.4 billion in net debt.
We have now delivered our net debt and structural cost reductions
targets and have line of sight on the remaining two of the four
primary financial targets we set ourselves for 2027.
Last week we announced an important step as we agreed with the
State of Louisiana to accelerate the delivery of our Deepwater
Horizon settlement commitments. Our intent is now to prioritize the
use of excess cashflow to address our remaining Deepwater Horizon
liabilities in full.
Deepwater Horizon was a tragedy. Eleven men lost their lives, and
communities and the environment across the Gulf Coast were
impacted. We will never forget - it changed bp. Its legacy guides
us in how we operate today, with safety at the heart of everything
we do.
And as we move forward, we will continue working with urgency to
turn one good set of results into strong performance quarter after
quarter. We have much more to do on the five priorities set out at
mid-year to deliver a step change in performance and realize the
full potential of this company.
Performance improvement priorities
Strengthening
the balance sheet: The combined sum of bp’s net debt, hybrids,
lease liabilities and Gulf of America settlement liabilities is
down by $9.3 billion compared with the second quarter of the year.
This is good progress, but we are still too leveraged and further
strengthening of the balance sheet remains our number one job. Our
goal is a strong balance sheet that, through the cycle, supports
the dividend and disciplined investment in service of delivering
value to shareholders.
BP p.l.c. Group results
Third quarter and nine months 2026
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|
Simplifying
the portfolio and investing
with discipline: We are moving at speed to simplify bp’s
portfolio to assets that best fit our integrated model and deliver
the most competitive cash and returns. In the quarter we agreed the
sale of our Austrian mobility and convenience business, completed
the sale of the Gelsenkirchen refinery, and announced plans to
market our North Sea and Archaea businesses. Still to come is the
expected imminent closure of the Castrol divestment, unlocking $6
billion to further strengthen the balance
sheet.
We have also de-risked exploration and production prospects in
Brazil, the Gulf of America and Iraq by bringing in partners. In
Venezuela we signed agreements for offshore gas production close to
our LNG facilities in Trinidad. We are being rigorous about where
we put capital and focusing on the most competitive opportunities.
But this quarter we recognized $4.0 billion of impairments linked
largely to transition businesses; we know we need to be better
stewards of our shareholders' capital.
Driving
operational excellence: The culture of ownership the bpx
energy team has built in the US
over the past three years
is showing up in
better execution, higher productivity and stronger returns.
And in refining this quarter,
availability and utilization improved and unit operating costs were
down, unlocking greater value from our assets. This improvement
needs to be sustained quarter on quarter and replicated across the
company.
Hardwiring
high performance and accountability: Senior leaders came together last month to hold up
the mirror on past performance, challenge ways of working, and make
new commitments on clearer accountabilities and better, faster
data-based decision-making. We are giving our people clarity on the
work they own, what they are expected to deliver and how success
will be measured – supported by a much simpler governance and
organizational structure that includes the return to upstream and
downstream businesses.
Simpler, stronger, more valuable bp
Our goal is to be a resilient business that delivers strong
performance in all price environments and grows long-term value for
our shareholders. In December we will set out our longer-term plans
and capital frame, alongside metrics and targets against which our
performance can be judged as we continue to build a simpler,
stronger, more valuable bp.
(a)
Divestment proceeds
are disposal proceeds as per the condensed group cash flow
statement. See page 4 for more
information.
(b)
See Note 9 for more
information.
(c)
Change in working
capital adjusted for inventory holding gains, fair value accounting
effects relating to subsidiaries and other adjusting items. See
page 27.
RC profit, underlying RC profit, net debt, underlying RC profit per
ordinary share, underlying RC profit per ADS and adjusted working
capital are non-IFRS measures. Inventory holding (gains) losses and
adjusting items are non-IFRS adjustments.
Definitions are provided in the Glossary on page 31. Non-IFRS
measures are marked with an asterisk.
|
The commentary above contains forward-looking statements and should
be read in conjunction with the cautionary statement on page
37.
|
3Q 2026 financial results summary
●
Underlying RC
profit* for the quarter was $8.5 billion, compared with $5.7
billion for the previous quarter. Compared with the second quarter
2026, the underlying result mainly reflects significantly higher
realized refining margins and significantly higher gas and
marketing trading result. The underlying effective tax rate (ETR)*
in the quarter was 28%, compared with 34% for the previous quarter,
which reflects changes in the geographical mix of
profits.
●
Reported
profit for the quarter was $4.7 billion, compared with
$3.9 billion for the second quarter 2026. The reported result
for the third quarter is adjusted for inventory holding gains* of
$1.6 billion (net of tax) and a net adverse impact of
adjusting items* of $5.4 billion (net of tax) to derive the
underlying RC profit. Adjusting items include adverse pre-tax fair
value accounting effects* of $0.5 billion and post-tax net
impairments of $4.0 billion (see page 26 for more information on adjusting
items).
●
Operating cash
flow for the quarter, after a $0.5 billion working capital*
release (after adjusting for inventory holding gains, fair value
accounting effects and other adjusting items), was $14.8 billion,
around $4.0 billion higher than the previous quarter, reflecting
higher underlying earnings, partly offset by $0.9 billion higher
income taxes paid.
●
Net debt*
was $13.9 billion at the end of the third quarter compared with
$22.3 billion at the end of the second quarter 2026. This reduction
reflects stronger cash generation during the quarter, partly offset
by $1.0 billion perpetual hybrid securities
redemption.
Segment results
●
Gas & low
carbon energy: The RC profit before interest and tax for the
third quarter 2026 was $0.2 billion, compared with
$1.6 billion for the previous quarter. After adjusting RC
profit before interest and tax for a net adverse impact of
adjusting items of $3.0 billion, the underlying RC profit
before interest and tax* for the third quarter was
$3.2 billion, compared with $2.1 billion in the second
quarter 2026. This reflects higher realizations which include the
impact of changes in non-Henry Hub natural gas marker prices. The
gas marketing and trading result was significantly higher than the
second quarter 2026.
●
Oil production
& operations: The RC profit before interest and tax for
the third quarter 2026 was $3.4 billion, compared with $3.4 billion
for the previous quarter. After adjusting RC profit before interest
and tax for a net adverse impact of adjusting items of $0.1
billion, the underlying RC profit before interest and tax for the
third quarter was $3.5 billion, compared with $3.6 billion for the
second quarter 2026. This reflects lower liquids realizations
partly offset by lower exploration write-offs.
●
Customers &
products: The RC profit before interest and tax for the
third quarter 2026 was $4.8 billion, compared with $5.1 billion for
the previous quarter. After adjusting RC profit before interest and
tax for a net adverse impact of adjusting items of $2.2 billion,
the underlying RC profit before interest and tax (underlying
result) for the third quarter was $6.9 billion, compared with $5.0
billion in the second quarter 2026. The customers third quarter
underlying result was lower by $0.5 billion, reflecting weaker
fuels margins and a lower result in Castrol and midstream, partly
offset by higher volumes due to seasonal effects and lower
underlying operating expenditure*. The products third quarter
underlying result was higher by $2.5 billion. In refining, the
result reflects significantly higher realized refining margins,
stronger commercial optimization, lower turnaround and maintenance
activity, and the absence of the impact of the prior-quarter third
party event at Whiting, partially offset by lower earnings
following the Gelsenkirchen divestment. The oil trading result was
slightly higher compared with the second quarter.
Financial results
In
addition to the highlights on page 3:
●
Profit attributable
to bp shareholders in the third quarter and nine months was
$4.7 billion and $12.4 billion respectively, compared
with $1.2 billion and $3.5 billion in the same periods of
2025.
–
After adjusting
profit attributable to bp shareholders for inventory holding gains*
and net impact of adjusting items*, underlying replacement cost
(RC) profit* for the third quarter and nine months was
$8.5 billion and $17.4 billion respectively, compared
with $2.2 billion and $5.9 billion for the same periods
of 2025. The underlying RC profit for the third quarter and nine
months compared with the same periods in 2025 mainly reflects
significantly higher realized refining margins and higher
realizations. The oil trading contribution and the gas marketing
and trading result for the third quarter and nine months were
significantly higher compared with the same periods in 2025. See
pages 7, 9 and 11 for more information.
–
Adjusting items in
the third quarter and nine months had a net adverse pre-tax impact
of $5.9 billion and $8.4 billion respectively, compared
with a net adverse pre-tax impact of $0.9 billion and
$2.0 billion in the same periods of 2025.
–
Adjusting items for
the third quarter and nine months include an adverse pre-tax impact
of fair value accounting effects* of $0.5 billion and $0.7 billion
respectively, compared with a favourable pre-tax impact of
$0.2 billion and $1.7 billion in the same periods of
2025. In both the gas & low carbon energy and customers &
products segments, fair value accounting effects represent the
difference in treatment between management’s internal
performance measure and IFRS. In customers & products, the
significant third quarter 2026 movement reflects changes in market
prices affecting the valuation of positions subject to fair value
accounting. In other businesses & corporate, the movements are
driven by foreign exchange and interest rates with a significant
favourable impact in the nine months 2025.
–
Adjusting items for
third quarter and nine months also include an adverse pre-tax
impairment impact of $4.1 billion and
$5.3 billion respectively,
compared with net impairment charges of $0.4 billion and
$1.9 billion for
the same periods in 2025. The 2026 charges are primarily
attributable to transition businesses in the gas & low carbon
energy segment.
●
The effective tax
rate (ETR) on the profit before taxation for the third quarter and
nine months was 40% and 43% respectively, compared with 53% and 52% for the
same periods in 2025. Excluding inventory holding gains or losses
and adjusting items, the underlying ETR* for the third quarter and
nine months was 28% and 31% respectively, compared with 39% and 41%
for the same periods in 2025. The lower underlying ETR for the
third quarter and nine months reflects changes in the geographical
mix of profits, particularly due to the higher results in products.
Underlying ETR is a non-IFRS measure.
●
Operating cash flow
for the third quarter and nine months was $14.8 billion and
$28.5 billion respectively, compared with $7.8 billion
and $16.9 billion for the same periods in 2025. The increases
reflect the higher underlying earnings in the periods.
●
Capital expenditure
in the third quarter and nine months was $3.0 billion and
$9.4 billion respectively, compared with $3.4 billion and
$10.4 billion in the same periods of 2025 reflecting our
decisions around capital spend.
●
Total divestment
and other proceeds for the third quarter and nine months were an
outflow of $21 million and an inflow of $0.8 billion
respectively, compared with inflows of $28 million and
$1.7 billion for the same periods in 2025. There were no other
proceeds in the third quarter 2026 and the third quarter 2025.
Other proceeds for the nine months 2025 were $1.0 billion from the
sale of a non-controlling interest in the subsidiary that holds our
12% share in the Trans-Anatolian natural gas pipeline
(TANAP).
●
At the end of the
third quarter, net debt* was $13.9 billion, compared with
$22.3 billion at the end of the second quarter 2026 and
$26.1 billion at the end of the third quarter
2025.
Analysis of RC profit (loss) before interest and tax and
reconciliation to profit (loss) for the period
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
RC profit (loss) before interest and tax
|
|
|
|
|
|
|
|
|
gas
& low carbon energy
|
|
208
|
1,564
|
1,097
|
|
2,826
|
3,502
|
|
oil
production & operations
|
|
3,405
|
3,397
|
2,119
|
|
8,457
|
6,823
|
|
customers
& products
|
|
4,796
|
5,100
|
1,610
|
|
12,348
|
2,685
|
|
other
businesses & corporate
|
|
(765)
|
(250)
|
(277)
|
|
(1,870)
|
346
|
|
Consolidation
adjustment – UPII*
|
|
—
|
—
|
(19
|
|
21
|
24
|
|
RC profit before interest and tax
|
|
7,644
|
9,811
|
4,530
|
|
21,782
|
13,380
|
|
Finance
costs and net finance expense relating to pensions and other
post-employment benefits
|
|
(1,071)
|
(1,120)
|
(1,212)
|
|
(3,312)
|
(3,654)
|
|
Taxation on a RC basis
|
|
(3,034)
|
(3,644)
|
(1,747)
|
|
(8,852)
|
(4,955)
|
|
Non-controlling interests
|
|
(441
|
(419)
|
(348)
|
|
(1,230)
|
(943)
|
|
RC profit attributable to bp shareholders*
|
|
3,098
|
4,628
|
1,223
|
|
8,388
|
3,828
|
|
Inventory holding gains (losses)*
|
|
2,040
|
(870)
|
(82)
|
|
5,329
|
(477)
|
|
Taxation (charge) credit on inventory holding gains and
losses
|
|
(442)
|
153
|
20
|
|
(1,268)
|
126
|
|
Profit for the period attributable to bp shareholders
|
|
4,696
|
3,911
|
1,161
|
|
12,449
|
3,477
|
Analysis of underlying RC profit (loss) before interest and
tax
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Underlying RC profit (loss) before interest and tax
|
|
|
|
|
|
|
|
|
gas
& low carbon energy
|
|
3,183
|
2,122
|
1,519
|
|
6,641
|
3,978
|
|
oil
production & operations
|
|
3,534
|
3,581
|
2,299
|
|
9,096
|
7,456
|
|
customers
& products
|
|
6,948
|
4,954
|
1,716
|
|
15,105
|
3,926
|
|
other
businesses & corporate
|
|
(222)
|
(345)
|
(189)
|
|
(839)
|
(344)
|
|
Consolidation
adjustment – UPII
|
|
—
|
—
|
(19)
|
|
21
|
24
|
|
Underlying RC profit before interest and tax
|
|
13,443
|
10,312
|
5,326
|
|
30,024
|
15,040
|
|
Finance
costs on an underlying RC basis(a) and net finance
expense relating to pensions and other post-employment
benefits
|
|
(1,020)
|
(1,053)
|
(1,129)
|
|
(3,120)
|
(3,306)
|
|
Taxation on an underlying RC basis
|
|
(3,524)
|
(3,108)
|
(1,639)
|
|
(8,286)
|
(4,847)
|
|
Non-controlling interests
|
|
(441)
|
(419)
|
(348)
|
|
(1,230)
|
(943)
|
|
Underlying RC profit attributable to bp shareholders*
|
|
8,458
|
5,732
|
2,210
|
|
17,388
|
5,944
|
(a)
A non-IFRS measure.
Finance costs on an underlying RC basis is defined as finance costs
as stated in the group income statement excluding finance costs
classified as adjusting items* (see footnote (e) on page
26).
Reconciliations
of underlying RC profit attributable to bp shareholders to the
nearest equivalent IFRS measure are provided on page 1 for the group and on pages 7-13
for the segments.
Operating Metrics
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Tier 1 and tier 2 process safety events(a)
|
|
8
|
20
|
8
|
|
35
|
23
|
|
upstream production(b)
(mboe/d)
|
|
2,220
|
2,201
|
2,362
|
|
2,253
|
2,301
|
|
upstream unit production costs(c)
($/boe)
|
|
6.54
|
6.62
|
6.19
|
|
6.51
|
6.44
|
|
bp-operated upstream plant reliability
|
|
95.3%
|
92.4%
|
96.8%
|
|
94.5%
|
96.3%
|
|
Refinery throughputs (mb/d)
|
|
1,396
|
1,467
|
1,516
|
|
1,463
|
1,433
|
|
bp-operated refining availability(b)
|
|
96.5%
|
94.7%
|
96.6%
|
|
95.8%
|
96.4%
|
(a)
Reported process
safety events are investigated throughout the year and as a result
there may be changes in previously reported events. See page
35 for more
information.
(b)
See Operational
updates on pages 7,
9 and 11. Because of rounding, upstream
production may not agree exactly with the sum of gas & low
carbon energy and oil production & operations.
(c)
The increase in the
nine months 2026, compared with the nine months 2025 mainly
reflects portfolio mix.
Outlook & Guidance
4Q 2026 guidance
●
Looking ahead, bp
expects fourth quarter 2026 reported upstream production to be
2,090 to 2,230mboe/d. This includes the impact of continued
disruption in the Middle East, activity phasing in bpx energy,
seasonally lower gas demand and around 20mboe/d for a weather event
in the Gulf of America, partly offset by the recovery from outages.
The heightened volatility in the oil and gas prices could also
impact PSA contracts.
●
In its customers
business, compared to the third quarter, bp expects a significantly
lower result with seasonally lower volumes, a lower midstream
result and lower Castrol earnings, subject to the anticipated
completion of the divestment. Fuels margins and midstream
performance are expected to remain sensitive to market
conditions.
●
In products, bp
expects throughput of 1,160-1,210mb/d, reflecting the absence of
Gelsenkirchen for the full quarter following its divestment on 31
July and higher maintenance activity. Refining margins are expected
to remain elevated and sensitive to the cost of supply and market
conditions.
●
bp expects income
taxes paid in the fourth quarter to be around $0.8 billion higher
than the third quarter 2026 mainly due to the impact of higher
profits on instalment payments.
2026 guidance
●
bp now expects
reported upstream production to be 2,210 to 2,250mboe/d, compared
with the 2025, 2,312mboe/d. This includes the impact of disruption
in the Middle East, the divestment of the Culzean gas field in the
UK North Sea and bp's reduced equity interest in Latin
America.
●
In its customers
business, bp expects to make continued progress growing cash flows,
supported by lower underlying operating expenditure* driven by
structural cost reductions*. These benefits will be partly offset
by the earnings impact of completed and announced divestments.
Reported earnings will benefit from lower depreciation as a result
of the assets held for sale accounting treatment of Castrol
following the planned divestment. Fuel margins are expected to
remain sensitive to conditions and developments in the Middle East
and any resulting policy responses.
●
In products, bp
expects throughput of 1,390 to 1,400mb/d, reflecting the completion
of the Gelsenkirchen divestment and a significantly lower level of
planned turnaround activity. Refining margins are expected to
remain sensitive to the cost of supply and market
conditions.
●
bp continues to
expect other businesses & corporate underlying annual charge to
be around $1.0 billion for 2026. The charge may vary quarter to
quarter.
●
bp continues to
expect the depreciation, depletion and amortization to be
$17.0-17.5 billion.
●
bp now expects the
underlying ETR* for 2026 to be between 31% and 34%, which reflects
the underlying ETR for the nine months of 31%. It is sensitive to a
range of factors, including the volatility of the price environment
and its impact on the geographical mix of the group’s profits
and losses.
●
bp continues to
expect capital expenditure to be $13.5-14.0 billion.
●
bp now expects
divestment and other proceeds to be around $8 billion in 2026,
including approximately $6 billion from the announced Castrol
divestment.
●
bp continues to
expect Gulf of America settlement payments for the year to be
around $1.6 billion pre-tax including $0.4 billion pre-tax paid
during the first quarter and $1.1 billion pre-tax paid during the
second quarter. The timing of the payment of the recently announced
$350 million settlement with the US state of Louisiana is still to
be determined.
|
The commentary above contains forward-looking statements and should
be read in conjunction with the cautionary statement on page
37.
|
gas & low carbon energy
Financial results
●
The replacement
cost (RC) profit before interest and tax for the third quarter and
nine months was $208 million and $2,826 million respectively,
compared with $1,097 million and $3,502 million for the same
periods in 2025. The third quarter and nine months are adjusted by
an adverse impact of net adjusting items* of $2,975 million and
$3,815 million respectively, compared with an adverse impact of net
adjusting items of $422 million and $476 million for the same
periods in 2025.
–
Adjusting items
include an impairment charge of $3,365 million and a net
impairment charge of $3,890 million for the third quarter and
nine months in 2026, primarily related to the group's transition
businesses, compared with net charges of $135 million and
$881 million for the same periods in 2025.
–
Adjusting items
also include the impacts of fair value accounting effects*,
relative to management's internal measure of performance, which are
a favourable impact of $644 million and $576 million for the third
quarter and nine months in 2026, and a favourable impact of $131
million and $817 million for the same periods in 2025. See page
26 for more information on
adjusting items.
●
After adjusting RC
profit before interest and tax for adjusting items, the underlying
RC profit before interest and tax* for the third quarter and nine
months was $3,183 million and $6,641 million respectively, compared
with $1,519 million and $3,978 million for the same periods in
2025.
●
The underlying RC
profit before interest and tax for the third quarter compared with
the same period in 2025, primarily reflects higher realizations.
The gas marketing and trading result was significantly
higher.
●
The underlying RC
profit before interest and tax for the nine months compared with
the same period in 2025, reflects higher realizations, a lower
depreciation, depletion and amortization charge and higher income
from equity-accounted entities. The gas marketing and trading
result was significantly higher.
Operational update
●
Reported production
for the quarter was 784mboe/d, 2.6% lower than the same period in
2025. Underlying production was 1.8% lower primarily due to base
decline in Egypt partly offset by ramp up of major
projects.
●
Reported production
for the nine months was 783mboe/d, 0.2% lower than the same period
in 2025. Underlying production was 0.4% higher mainly due to ramp
up of major projects partly offset by base decline.
Strategic progress
●
In August, bp
agreed to acquire Woodside Energy’s 70% interest in Block
TTDAA 14, the Calypso gas project in Trinidad and Tobago,
increasing bp’s stake to 100% and assuming operatorship. The
transaction is subject to regulatory approvals.
●
In August, bp and
the government of the Bolivarian Republic of Venezuela signed
agreements to advance offshore gas development, including the award
of an exploration and production licence for Phase 2 of the Loran
field in the Plataforma Deltana area. The licence has been granted
with bp as operator and in partnership with XRG and UCC Oil and Gas
Holding LLC, with each party holding an equal working interest
share. Loran Phase 2 contains an estimated 4 trillion cubic feet of
recoverable gas resources.
●
In August, bp
agreed terms for the National Gas Company of Trinidad and Tobago
Limited to acquire a 20% participating interest in Block 5(b),
aligning interests across the Manakin-Cocuina cross-border gas
development between Trinidad and Tobago and Venezuela, subject to
regulatory approvals.
●
In September, bp
entered into an agreement to sell a 5% interest in the Browse
project in Western Australia to Osaka Gas Browse Pty Ltd, reducing
bp's working interest to 34.33%. The transaction is subject to
regulatory and partner approvals.
●
In September, bp
completed the farm down in Indonesia, of a 50% participating
interest in the bp operated Agung I and Agung II exploration blocks
to INPEX, reducing bp’s working interest to 50%.
gas & low carbon energy (continued)
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Profit before interest and tax
|
|
208
|
1,564
|
1,097
|
|
2,826
|
3,502
|
|
Inventory holding (gains) losses*
|
|
—
|
—
|
—
|
|
—
|
—
|
|
RC profit before interest and tax
|
|
208
|
1,564
|
1,097
|
|
2,826
|
3,502
|
|
Net (favourable) adverse impact of adjusting items
|
|
2,975
|
558
|
422
|
|
3,815
|
476
|
|
Underlying RC profit before interest and tax
|
|
3,183
|
2,122
|
1,519
|
|
6,641
|
3,978
|
|
Taxation on an underlying RC basis
|
|
(906)
|
(706)
|
(529)
|
|
(2,085)
|
(1,509)
|
|
Underlying RC profit before interest
|
|
2,277
|
1,416
|
990
|
|
4,556
|
2,469
|
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
1,228
|
1,139
|
1,223
|
|
3,553
|
3,796
|
|
|
|
|
|
|
|
|
|
|
Exploration write-offs
|
|
|
|
|
|
|
|
|
Exploration write-offs
|
|
18
|
48
|
29
|
|
66
|
30
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA*
|
|
|
|
|
|
|
|
|
Total adjusted EBITDA
|
|
4,429
|
3,309
|
2,771
|
|
10,260
|
7,804
|
|
|
|
|
|
|
|
|
|
|
Capital expenditure
|
|
|
|
|
|
|
|
|
gas
|
|
816
|
717
|
727
|
|
2,168
|
2,189
|
|
low carbon energy
|
|
100
|
59
|
101
|
|
219
|
332
|
|
Total capital expenditure
|
|
916
|
776
|
828
|
|
2,387
|
2,521
|
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Production (net of
royalties)(a)
|
|
|
|
|
|
|
|
|
Liquids (mb/d)
|
|
80
|
88
|
87
|
|
85
|
85
|
|
Natural gas (mmcf/d)
|
|
4,085
|
3,928
|
4,167
|
|
4,045
|
4,054
|
|
Total hydrocarbons (mboe/d)
|
|
784
|
765
|
806
|
|
783
|
784
|
|
|
|
|
|
|
|
|
|
|
Average realizations(b)
|
|
|
|
|
|
|
|
|
Liquids ($/bbl)
|
|
85.05
|
94.09
|
64.57
|
|
82.43
|
66.31
|
|
Natural gas ($/mcf)
|
|
8.65
|
8.03
|
6.41
|
|
7.66
|
6.71
|
|
Total hydrocarbons ($/boe)
|
|
53.92
|
52.82
|
40.30
|
|
48.90
|
42.06
|
(a)
Includes bp’s
share of production of equity-accounted entities in the gas &
low carbon energy segment.
(b)
Realizations are
based on sales by consolidated subsidiaries only – this
excludes equity-accounted entities.
oil production & operations
Financial results
●
The replacement
cost (RC) profit before interest and tax for the third quarter and
nine months was $3,405 million and $8,457 million respectively,
compared with $2,119 million and $6,823 million for the same
periods in 2025. The third quarter and nine months are adjusted by
an adverse impact of net adjusting items* of $129 million and $639
million respectively, compared with an adverse impact of net
adjusting items of $180 million and $633 million for the same
periods in 2025. See page 26
for more information on adjusting items.
●
After adjusting RC
profit before interest and tax for adjusting items, the underlying
RC profit before interest and tax* for the third quarter and nine
months was $3,534 million and $9,096 million respectively, compared
with $2,299 million and $7,456 million for the same periods in
2025.
●
The underlying RC
profit before interest and tax for the third quarter, compared with
the same period in 2025, primarily reflects higher realizations
partly offset by divestment of the Culzean gas field in the UK
North Sea.
●
The underlying RC
profit before interest and tax for the nine months, compared with
the same period in 2025, reflects higher realizations, partly
offset by higher exploration write-offs mainly due to the sale of
Bay du Nord in Canada and the divestment of the Culzean gas field
in the UK North Sea.
Operational update
●
Reported production
for the quarter was 1,436mboe/d, 7.8% lower than the same period in
2025. Underlying production for the quarter was 1.1% lower mainly
due to maintenance and base decline partly offset by higher
production in bpx energy.
●
Reported production
for the nine months was 1,470mboe/d, 3.1% lower than the same
period in 2025. Underlying production for the nine months was 2.1%
higher mainly due to higher production in bpx energy and ramp up of
major projects partly offset by seasonal maintenance.
Strategic progress
●
In August, bp was
the highest bidder on five blocks in the BBG-3 Gulf of America
lease sale.
●
In August, Aker BP
started production from the Skarv Satellite Project (bp interest in
Aker BP 15.9%), which comprises the Alve Nord, Idun Nord and
Ørn fields in the Norwegian Sea. The developments represent
approximately 120 million barrels of oil equivalent of recoverable
resources.
●
In September, bp
agreed terms for Shell to acquire a 50% stake in the Tupinambá
exploration block in the Santos Basin, offshore Brazil, in addition
to a 30% stake in five leases containing the Conifer exploration
prospect in the deepwater Gulf of America Paleogene. bp will retain
the remaining 50% interest in Tupinambá and 70% in Conifer and
continue as operator in both. The transaction remains subject to
regulatory approvals.
●
In September, bp on
behalf of the partnership, reached an agreement to transport and
process third-party gas and condensate from the Absheron field in
Azerbaijan. Gas will be transported through the South Caucasus
Pipeline (SCP), while condensate will be processed at the
bp-operated Shah Deniz 2 gas plant and transported through the
Baku-Tbilisi-Ceyhan (BTC) pipeline.
oil production & operations (continued)
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Profit before interest and tax
|
|
3,407
|
3,396
|
2,116
|
|
8,465
|
6,825
|
|
Inventory holding (gains) losses*
|
|
(2)
|
1
|
3
|
|
(8)
|
(2)
|
|
RC profit before interest and tax
|
|
3,405
|
3,397
|
2,119
|
|
8,457
|
6,823
|
|
Net (favourable) adverse impact of adjusting items
|
|
129
|
184
|
180
|
|
639
|
633
|
|
Underlying RC profit before interest and tax
|
|
3,534
|
3,581
|
2,299
|
|
9,096
|
7,456
|
|
Taxation on an underlying RC basis
|
|
(1,378)
|
(1,659)
|
(1,054)
|
|
(3,891)
|
(3,491)
|
|
Underlying RC profit before interest
|
|
2,156
|
1,922
|
1,245
|
|
5,205
|
3,965
|
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
1,861
|
1,754
|
1,961
|
|
5,624
|
5,681
|
|
|
|
|
|
|
|
|
|
|
Exploration write-offs
|
|
|
|
|
|
|
|
|
Exploration write-offs
|
|
(3)
|
478
|
154
|
|
477
|
288
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA*
|
|
|
|
|
|
|
|
|
Total adjusted EBITDA
|
|
5,392
|
5,813
|
4,414
|
|
15,197
|
13,425
|
|
|
|
|
|
|
|
|
|
|
Capital expenditure
|
|
|
|
|
|
|
|
|
Total capital expenditure
|
|
1,612
|
1,733
|
1,722
|
|
5,236
|
5,124
|
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Production (net of
royalties)(a)
|
|
|
|
|
|
|
|
|
Liquids (mb/d)
|
|
1,008
|
997
|
1,121
|
|
1,043
|
1,107
|
|
Natural gas (mmcf/d)
|
|
2,482
|
2,543
|
2,525
|
|
2,478
|
2,374
|
|
Total hydrocarbons (mboe/d)
|
|
1,436
|
1,436
|
1,556
|
|
1,470
|
1,517
|
|
|
|
|
|
|
|
|
|
|
Average realizations(b)
|
|
|
|
|
|
|
|
|
Liquids ($/bbl)
|
|
76.42
|
84.10
|
59.58
|
|
73.23
|
62.17
|
|
Natural gas ($/mcf)
|
|
2.83
|
2.16
|
3.32
|
|
2.84
|
3.87
|
|
Total hydrocarbons ($/boe)
|
|
57.59
|
62.18
|
47.89
|
|
56.05
|
50.99
|
(a)
Includes bp’s
share of production of equity-accounted entities in the oil
production & operations segment.
(b)
Realizations are
based on sales by consolidated subsidiaries only – this
excludes equity-accounted entities.
customers & products
Financial results
●
The replacement
cost (RC) profit before interest and tax for the third quarter and
nine months was $4,796 million and $12,348 million respectively,
compared with $1,610 million and $2,685 million for the same
periods in 2025. The third quarter and nine months are adjusted by
an adverse impact of net adjusting items* of $2,152 million and
$2,757 million respectively, compared with an adverse impact of net
adjusting items of $106 million and $1,241 million for the same
periods in 2025. See page 26
for more information on adjusting items.
●
After adjusting RC
profit before interest and tax for adjusting items, the underlying
RC profit before interest and tax* (underlying result) for the
third quarter and nine months was $6,948 million and $15,105
million respectively, compared with $1,716 million and $3,926
million for the same periods in 2025.
●
The customers &
products underlying result for the third quarter and nine months
was significantly higher compared with the same periods in 2025,
reflecting a stronger performance across both
sub-segments.
●
customers – the customers underlying result for the
third quarter was slightly higher compared with the same period in
2025, reflecting a stronger midstream performance and lower
underlying operating expenditure*, largely offset by lower fuels
margins and a lower contribution from bioenergy. The customers
underlying result for the nine months was significantly higher
compared with the same period in 2025, driven by a stronger
midstream performance, higher earnings in Castrol and a lower
underlying operating expenditure and depreciation, partly offset by
lower fuels volumes and margins, and a lower contribution from
bioenergy.
●
products – the products underlying result for the
third quarter and nine months was significantly higher compared
with the same periods in 2025. In refining, the third quarter
result benefited from significantly higher realized refining
margins, stronger commercial optimization, and lower turnaround
activity. In refining, the result for the nine months benefited
from significantly higher realized refining margins, stronger
commercial optimization and crude selection timing effect, and
significantly lower turnaround activity, partly offset by
production impacts from operational and maintenance events. The oil
trading contribution for the third quarter and nine months was
significantly higher compared with the same periods in
2025.
Operational update
●
bp-operated
refining availability for the third quarter and nine months was
96.5% and 95.8% respectively, lower compared with 96.6% and 96.4%
for the same periods in 2025.
Strategic progress
●
In New Zealand, bp
committed to securing additional diesel and jet fuel storage
capacity at Channel Infrastructure, strengthening fuel supply
resilience and supporting future customer demand.
●
The Castrol
divestment is expected imminently and remains on track to complete
within agreed timelines.
customers & products (continued)
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Profit before interest and tax
|
|
6,834
|
4,231
|
1,531
|
|
17,669
|
2,206
|
|
Inventory holding (gains) losses*
|
|
(2,038)
|
869
|
79
|
|
(5,321)
|
479
|
|
RC profit before interest and tax
|
|
4,796
|
5,100
|
1,610
|
|
12,348
|
2,685
|
|
Net (favourable) adverse impact of adjusting items
|
|
2,152
|
(146)
|
106
|
|
2,757
|
1,241
|
|
Underlying RC profit before interest and tax
|
|
6,948
|
4,954
|
1,716
|
|
15,105
|
3,926
|
|
Of
which:(a)
|
|
|
|
|
|
|
|
|
customers
– convenience & mobility
|
|
1,223
|
1,771
|
1,167
|
|
4,003
|
2,887
|
|
Castrol – included in customers
|
|
285
|
429
|
261
|
|
1,060
|
744
|
|
products
– refining & trading
|
|
5,725
|
3,183
|
549
|
|
11,102
|
1,039
|
|
Taxation on an underlying RC basis
|
|
(1,415)
|
(1,034)
|
(360)
|
|
(3,095)
|
(687)
|
|
Underlying RC profit before interest
|
|
5,533
|
3,920
|
1,356
|
|
12,010
|
3,239
|
(a)
A reconciliation to
RC profit before interest and tax by business is provided on page
29.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Adjusted EBITDA*(b)
|
|
|
|
|
|
|
|
|
customers – convenience & mobility
|
|
1,796
|
2,340
|
1,786
|
|
5,677
|
4,715
|
|
Castrol – included in customers
|
|
285
|
429
|
309
|
|
1,060
|
888
|
|
products – refining & trading
|
|
6,153
|
3,616
|
975
|
|
12,395
|
2,301
|
|
|
|
7,949
|
5,956
|
2,761
|
|
18,072
|
7,016
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
1,001
|
1,002
|
1,045
|
|
2,967
|
3,090
|
|
|
|
|
|
|
|
|
|
|
Capital expenditure
|
|
|
|
|
|
|
|
|
customers – convenience & mobility
|
|
322
|
309
|
386
|
|
998
|
1,358
|
|
Castrol – included in customers
|
|
(4)
|
(3)
|
37
|
|
8
|
110
|
|
products – refining & trading
|
|
161
|
229
|
384
|
|
680
|
1,152
|
|
Total capital expenditure
|
|
483
|
538
|
770
|
|
1,678
|
2,510
|
(a)
A reconciliation to
RC profit before interest and tax by business is provided on page
29.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
Marketing sales of refined products (mb/d)
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
US
|
|
1,248
|
1,189
|
1,273
|
|
1,203
|
1,240
|
|
Europe
|
|
968
|
986
|
1,046
|
|
959
|
1,000
|
|
Rest of World
|
|
454
|
449
|
456
|
|
454
|
463
|
|
|
|
2,670
|
2,624
|
2,775
|
|
2,616
|
2,703
|
|
Trading/supply sales of refined products
|
|
488
|
539
|
557
|
|
501
|
492
|
|
Total sales volume of refined products
|
|
3,158
|
3,163
|
3,332
|
|
3,117
|
3,195
|
|
bp average refining indicator
margin (RIM)
($/bbl)
|
46.7
|
29.6
|
15.8
|
|
31.2
|
12.0
|
|
|
Refinery throughputs (mb/d)
|
|
|
|
|
|
|
|
|
US
|
|
720
|
626
|
683
|
|
676
|
643
|
|
Europe
|
|
676
|
841
|
833
|
|
787
|
790
|
|
Total refinery throughputs
|
|
1,396
|
1,467
|
1,516
|
|
1,463
|
1,433
|
|
|
|
|
|
|
|
|
|
|
bp-operated refining availability (%)
|
|
96.5
|
94.7
|
96.6
|
|
95.8
|
96.4
|
other businesses & corporate
Other
businesses & corporate comprises technology, bp ventures,
shipping, our corporate activities & functions and any residual
costs of the Gulf of America oil spill.
Financial results
●
The replacement
cost (RC) loss before interest and tax for the third quarter and
nine months was $765 million and $1,870 million respectively,
compared with a loss of $277 million and a profit of $346 million
for the same periods in 2025. The third quarter and nine months are
adjusted by an adverse impact of net adjusting items* of $543
million and $1,031 million respectively, compared with an adverse
impact of net adjusting items of $88 million and a favourable
impact of $690 million for the same periods in 2025. Adjusting
items include an adverse impact of fair value accounting effects*
of $92 million and $196 million for the third quarter and nine
months, and an adverse impact of $13 million and a favourable
impact of $1,096 million for the same periods in 2025. See page
26 for more information on
adjusting items.
●
After adjusting RC
loss before interest and tax for adjusting items, the underlying RC
loss before interest and tax* for the third quarter and nine months
was $222 million and $839 million respectively, compared with a
loss of $189 million and $344 million for the same periods in
2025.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Profit (loss) before interest and tax
|
|
(765)
|
(250)
|
(277)
|
|
(1,870)
|
346
|
|
Inventory holding (gains) losses*
|
|
—
|
—
|
—
|
|
—
|
—
|
|
RC profit (loss) before interest and tax
|
|
(765)
|
(250)
|
(277)
|
|
(1,870)
|
346
|
|
Net
(favourable) adverse impact of adjusting items(a)
|
|
543
|
(95
|
88
|
|
1,031
|
(690)
|
|
Underlying RC profit (loss) before interest and tax
|
|
(222)
|
(345)
|
(189)
|
|
(839)
|
(344)
|
|
Taxation on an underlying RC basis
|
|
(16)
|
91
|
106
|
|
199
|
248
|
|
Underlying RC profit (loss) before interest
|
|
(238)
|
(254)
|
(83)
|
|
(640)
|
(96)
|
(a)
Includes fair value
accounting effects relating to hybrid bonds. See page 32 for more information.
Financial statements
Group income statement
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
|
|
|
|
|
|
|
|
|
Sales
and other operating revenues (Note 5)
|
|
68,399
|
69,105
|
48,420
|
|
189,759
|
141,952
|
|
Earnings from joint ventures – after interest and
tax
|
|
598
|
438
|
176
|
|
1,359
|
744
|
|
Earnings from associates – after interest and
tax
|
|
413
|
145
|
275
|
|
911
|
679
|
|
Interest and other income
|
|
455
|
411
|
397
|
|
1,204
|
1,157
|
|
Gains on sale of businesses and fixed assets
|
|
19
|
15
|
(18
|
|
136
|
275
|
|
Total revenues and other income
|
|
69,884
|
70,114
|
49,250
|
|
193,369
|
144,807
|
|
Purchases
|
|
38,354
|
41,149
|
28,031
|
|
105,753
|
82,626
|
|
Production and manufacturing expenses
|
|
7,641
|
8,954
|
6,620
|
|
25,132
|
18,887
|
|
Production and similar taxes
|
|
542
|
629
|
431
|
|
1,600
|
1,292
|
|
Depreciation,
depletion and amortization (Note 6)
|
|
4,353
|
4,149
|
4,472
|
|
12,912
|
13,296
|
|
Net
impairment and losses on sale of businesses and fixed assets (Note
3)
|
|
4,364
|
1,100
|
753
|
|
6,053
|
2,413
|
|
Exploration expense
|
|
52
|
582
|
224
|
|
678
|
466
|
|
Distribution and administration expenses
|
|
4,894
|
4,610
|
4,271
|
|
14,130
|
12,924
|
|
Profit (loss) before interest and taxation
|
|
9,684
|
8,941
|
4,448
|
|
27,111
|
12,903
|
|
Finance costs
|
|
1,120
|
1,175
|
1,267
|
|
3,470
|
3,817
|
|
Net
finance (income) expense relating to pensions and other
post-employment benefits
|
|
(49)
|
(55)
|
(55)
|
|
(158)
|
(163)
|
|
Profit (loss) before taxation
|
|
8,613
|
7,821
|
3,236
|
|
23,799
|
9,249
|
|
Taxation
|
|
3,476
|
3,491
|
1,727
|
|
10,120
|
4,829
|
|
Profit (loss) for the period
|
|
5,137
|
4,330
|
1,509
|
|
13,679
|
4,420
|
|
Attributable to
|
|
|
|
|
|
|
|
|
bp
shareholders
|
|
4,696
|
3,911
|
1,161
|
|
12,449
|
3,477
|
|
Non-controlling
interests
|
|
441
|
419
|
348
|
|
1,230
|
943
|
|
|
|
5,137
|
4,330
|
1,509
|
|
13,679
|
4,420
|
|
|
|
|
|
|
|
|
|
|
Earnings per share (Note 7)
|
|
|
|
|
|
|
|
|
Profit (loss) for the period attributable to bp
shareholders
|
|
|
|
|
|
|
|
|
Per
ordinary share (cents)
|
|
|
|
|
|
|
|
|
Basic
|
|
30.19
|
24.77
|
7.48
|
|
79.81
|
22.22
|
|
Diluted
|
|
29.89
|
24.54
|
7.38
|
|
78.79
|
21.77
|
|
Per
ADS (dollars)
|
|
|
|
|
|
|
|
|
Basic
|
|
1.81
|
1.49
|
0.45
|
|
4.79
|
1.33
|
|
Diluted
|
|
1.79
|
1.47
|
0.44
|
|
4.73
|
1.31
|
Condensed group statement of comprehensive income
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
|
|
|
|
|
|
|
|
|
Profit (loss) for the period
|
|
5,137
|
4,330
|
1,509
|
|
13,679
|
4,420
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
Items that may be reclassified subsequently to profit or
loss
|
|
|
|
|
|
|
|
|
Currency
translation differences(a)
|
|
(320)
|
65
|
(276)
|
|
(446)
|
1,866
|
|
Exchange (gains)
losses on translation of foreign operations reclassified to gain or
loss on sale of businesses and fixed assets(b)
|
|
345
|
2
|
22
|
|
347
|
22
|
|
Cash
flow hedges and costs of hedging
|
|
37
|
(8)
|
134
|
|
188
|
184
|
|
Share
of items relating to equity-accounted entities, net of
tax
|
|
45
|
(1)
|
(5)
|
|
51
|
(1)
|
|
Income
tax relating to items that may be reclassified
|
|
(12)
|
(15)
|
(3)
|
|
(41)
|
(18)
|
|
|
|
95
|
43
|
(128)
|
|
99
|
2,053
|
|
Items that will not be reclassified to profit or loss
|
|
|
|
|
|
|
|
|
Remeasurements
of the net pension and other post-employment benefit liability or
asset
|
|
378
|
(364)
|
(447)
|
|
133
|
(330)
|
|
Remeasurements
of equity investments
|
|
—
|
3
|
—
|
|
2
|
1
|
|
Cash
flow hedges that will subsequently be transferred to the balance
sheet
|
|
1
|
—
|
(1)
|
|
4
|
3
|
|
Income
tax relating to items that will not be reclassified
|
|
(101)
|
91
|
126
|
|
(47)
|
83
|
|
|
|
278
|
(270)
|
(322)
|
|
92
|
(243)
|
|
Other comprehensive income
|
|
373
|
(227)
|
(450)
|
|
191
|
1,810
|
|
Total comprehensive income
|
|
5,510
|
4,103
|
1,059
|
|
13,870
|
6,230
|
|
Attributable to
|
|
|
|
|
|
|
|
|
bp
shareholders
|
|
5,075
|
3,700
|
726
|
|
12,691
|
5,165
|
|
Non-controlling
interests
|
|
435
|
403
|
333
|
|
1,179
|
1,065
|
|
|
|
5,510
|
4,103
|
1,059
|
|
13,870
|
6,230
|
(a)
Nine months 2025 is
principally affected by movements in the Pound Sterling against the
US dollar.
(b)
Third quarter 2026
relates to the divestment of the Gelsenkirchen
refinery.
Condensed group statement of changes in equity
|
|
|
bp shareholders’
|
Non-controlling interests
|
Total
|
|
|
$ million
|
|
equity
|
Hybrid bonds
|
Other interest
|
equity
|
|
At 1 January 2026
|
|
53,052
|
15,955
|
4,993
|
74,000
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
12,691
|
532
|
647
|
13,870
|
|
Dividends
|
|
(3,921)
|
—
|
(662)
|
(4,583)
|
|
Cash
flow hedges transferred to the balance sheet, net of
tax
|
|
(1)
|
—
|
—
|
(1)
|
|
Repurchase of ordinary share capital
|
|
(114)
|
—
|
—
|
(114)
|
|
Share-based payments, net of tax
|
|
722
|
—
|
—
|
722
|
|
Redemption of
perpetual hybrid bonds, net of tax(a)
|
|
(65)
|
(3,816)
|
—
|
(3,881)
|
|
Payments on perpetual hybrid bonds
|
|
—
|
(568)
|
—
|
(568)
|
|
Transactions
involving non-controlling interests, net of tax
|
|
(191)
|
—
|
339
|
148
|
|
At 30 September 2026
|
|
62,173
|
12,103
|
5,317
|
79,593
|
|
|
|
|
|
|
|
|
|
|
bp shareholders’
|
Non-controlling interests
|
Total
|
|
|
$ million
|
|
equity
|
Hybrid bonds
|
Other interest
|
equity
|
|
At 1 January 2025
|
|
59,246
|
16,649
|
2,423
|
78,318
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
5,165
|
607
|
458
|
6,230
|
|
Dividends
|
|
(3,805)
|
—
|
(386)
|
(4,191)
|
|
Cash
flow hedges transferred to the balance sheet, net of
tax
|
|
(5)
|
—
|
—
|
(5)
|
|
Repurchase of ordinary share capital
|
|
(3,261)
|
—
|
—
|
(3,261)
|
|
Share-based payments, net of tax
|
|
908
|
—
|
—
|
908
|
|
Share
of equity-accounted entities’ changes in equity, net of
tax
|
|
1
|
—
|
—
|
1
|
|
Issue of perpetual hybrid bonds
|
|
—
|
500
|
—
|
500
|
|
Redemption of perpetual hybrid bonds, net of tax
|
|
—
|
(1,200)
|
—
|
(1,200)
|
|
Payments on perpetual hybrid bonds
|
|
(9)
|
(618)
|
—
|
(627)
|
|
Transactions
involving non-controlling interests, net of tax
|
|
4
|
—
|
968
|
972
|
|
At 30 September 2025
|
|
58,244
|
15,938
|
3,463
|
77,645
|
(a) In
the nine months 2026, BP Capital Markets p.l.c. exercised its
option to redeem €2.5 billion of hybrid bonds. During the
third quarter 2026, a group subsidiary redeemed perpetual
subordinated hybrid securities of $1.0 billion which had previously
been specifically earmarked to fund BP Alternative Energy
Investments Ltd., including the funding of Lightsource
bp.
Group balance sheet
|
|
|
30 September
|
31 December
|
|
$ million
|
|
2026
|
2025
|
|
Non-current assets
|
|
|
|
|
Property, plant and equipment
|
|
95,257
|
98,633
|
|
Goodwill
|
|
9,233
|
10,300
|
|
Intangible assets
|
|
8,143
|
8,197
|
|
Investments in joint ventures
|
|
11,399
|
13,400
|
|
Investments in associates
|
|
7,317
|
7,325
|
|
Other investments
|
|
661
|
857
|
|
Fixed assets
|
|
132,010
|
138,712
|
|
Loans
|
|
1,663
|
1,991
|
|
Trade and other receivables
|
|
2,490
|
2,376
|
|
Derivative financial instruments
|
|
21,641
|
20,957
|
|
Prepayments
|
|
637
|
608
|
|
Deferred tax assets
|
|
2,499
|
4,325
|
|
Defined benefit pension plan surpluses
|
|
7,309
|
7,771
|
|
|
|
168,249
|
176,740
|
|
Current assets
|
|
|
|
|
Loans
|
|
375
|
457
|
|
Inventories
|
|
30,965
|
22,499
|
|
Trade and other receivables
|
|
39,765
|
26,014
|
|
Derivative financial instruments
|
|
9,518
|
5,180
|
|
Prepayments
|
|
2,067
|
3,422
|
|
Current tax receivable
|
|
715
|
1,153
|
|
Other investments
|
|
60
|
158
|
|
Cash and cash equivalents
|
|
42,993
|
36,556
|
|
|
|
126,458
|
95,439
|
|
Assets
classified as held for sale (Note 2)
|
|
9,014
|
6,347
|
|
|
|
135,472
|
101,786
|
|
Total assets
|
|
303,721
|
278,526
|
|
Current liabilities
|
|
|
|
|
Trade and other payables
|
|
69,070
|
56,843
|
|
Derivative financial instruments
|
|
9,792
|
4,413
|
|
Accruals
|
|
5,870
|
5,572
|
|
Lease liabilities
|
|
3,013
|
2,832
|
|
Finance debt
|
|
5,975
|
3,356
|
|
Current tax payable
|
|
3,436
|
1,262
|
|
Provisions
|
|
4,772
|
4,709
|
|
|
|
101,928
|
78,987
|
|
Liabilities
directly associated with assets classified as held for sale (Note
2)
|
|
3,128
|
1,594
|
|
|
|
105,056
|
80,581
|
|
Non-current liabilities
|
|
|
|
|
Other payables
|
|
7,089
|
7,975
|
|
Derivative financial instruments
|
|
21,678
|
19,667
|
|
Accruals
|
|
1,924
|
1,834
|
|
Lease liabilities
|
|
11,237
|
11,739
|
|
Finance debt
|
|
49,391
|
54,602
|
|
Deferred tax liabilities
|
|
8,172
|
7,642
|
|
Provisions
|
|
15,732
|
15,670
|
|
Defined benefit pension plan and other post-employment benefit plan
deficits
|
|
3,849
|
4,816
|
|
|
|
119,072
|
123,945
|
|
Total liabilities
|
|
224,128
|
204,526
|
|
Net assets
|
|
79,593
|
74,000
|
|
Equity
|
|
|
|
|
bp
shareholders’ equity
|
|
62,173
|
53,052
|
|
Non-controlling interests
|
|
17,420
|
20,948
|
|
Total equity
|
|
79,593
|
74,000
|
Condensed group cash flow statement
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Operating activities
|
|
|
|
|
|
|
|
|
Profit (loss) before taxation
|
|
8,613
|
7,821
|
3,236
|
|
23,799
|
9,249
|
|
Adjustments to
reconcile profit (loss) before taxation to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization and exploration expenditure written
off
|
|
4,369
|
4,675
|
4,655
|
|
13,456
|
13,614
|
|
Net
impairment and (gain) loss on sale of businesses and fixed
assets
|
|
4,345
|
1,085
|
771
|
|
5,917
|
2,138
|
|
Earnings
from equity-accounted entities, less dividends
received
|
|
(351)
|
51
|
192
|
|
(667)
|
32
|
|
Net
charge for interest and other finance expense, less net interest
paid
|
|
371
|
151
|
470
|
|
557
|
743
|
|
Share-based
payments
|
|
181
|
201
|
264
|
|
700
|
880
|
|
Net
operating charge for pensions and other post-employment benefits,
less contributions and benefit payments for unfunded
plans
|
|
299
|
(18
|
(96)
|
|
252
|
(143)
|
|
Net
charge for provisions, less payments
|
|
(2,123)
|
948
|
(60)
|
|
1,182
|
1,710
|
|
Movements in
inventories and other current and non-current assets and
liabilities
|
|
1,428
|
(2,675)
|
494
|
|
(11,789)
|
(6,605)
|
|
Income
taxes paid
|
|
(2,303)
|
(1,381)
|
(2,140)
|
|
(4,860)
|
(4,727)
|
|
Net cash provided by operating activities
|
|
14,829
|
10,858
|
7,786
|
|
28,547
|
16,891
|
|
Investing activities
|
|
|
|
|
|
|
|
|
Expenditure
on property, plant and equipment, intangible and other
assets
|
|
(2,964)
|
(3,087)
|
(3,171)
|
|
(9,293)
|
(9,758)
|
|
Acquisitions, net of cash acquired
|
|
(3)
|
9
|
(52)
|
|
(8)
|
(293)
|
|
Investment in joint ventures
|
|
(64)
|
(8)
|
(128)
|
|
(94)
|
(245)
|
|
Investment in associates
|
|
(5)
|
—
|
(30)
|
|
(17)
|
(69)
|
|
Total cash capital expenditure
|
|
(3,036)
|
(3,086)
|
(3,381)
|
|
(9,412)
|
(10,365)
|
|
Proceeds from disposal of fixed assets
|
|
50
|
425
|
30
|
|
634
|
644
|
|
Proceeds from disposal of businesses, net of cash
disposed
|
|
(71)
|
184
|
(2)
|
|
215
|
110
|
|
Proceeds from loan repayments
|
|
72
|
31
|
48
|
|
135
|
110
|
|
Cash provided from investing activities
|
|
51
|
640
|
76
|
|
984
|
864
|
|
Net cash used in investing activities
|
|
(2,985)
|
(2,446)
|
(3,305)
|
|
(8,428)
|
(9,501)
|
|
Financing activities
|
|
|
|
|
|
|
|
|
Net
issue (repurchase) of shares (Note 7)
|
|
—
|
—
|
(750)
|
|
(562)
|
(3,660)
|
|
Lease liability payments
|
|
(769)
|
(761)
|
(816)
|
|
(2,294)
|
(2,327)
|
|
Proceeds from long-term financing
|
|
11
|
1,170
|
1,028
|
|
1,248
|
2,237
|
|
Repayments of long-term financing
|
|
(2,366)
|
(21)
|
(1,250)
|
|
(3,232)
|
(3,464)
|
|
Net increase (decrease) in short-term debt
|
|
(97)
|
(2,726)
|
104
|
|
289
|
18
|
|
Issue of perpetual hybrid bonds
|
|
—
|
—
|
—
|
|
—
|
500
|
|
Redemption
of perpetual hybrid bonds(a)
|
|
(1,000)
|
(2,855)
|
(1,200)
|
|
(3,855)
|
(1,200)
|
|
Payments relating to perpetual hybrid bonds
|
|
(178)
|
(293)
|
(284)
|
|
(708)
|
(888)
|
|
Payments
relating to transactions involving non-controlling interests (Other
interest)
|
|
(9)
|
—
|
(2)
|
|
(22)
|
(2)
|
|
Receipts
relating to transactions involving non-controlling interests (Other
interest)
|
|
—
|
1
|
8
|
|
1
|
973
|
|
Dividends paid - bp shareholders
|
|
(1,345)
|
(1,302)
|
(1,288)
|
|
(3,925)
|
(3,783)
|
|
-
non-controlling interests
|
|
(287)
|
(206)
|
(155)
|
|
(668)
|
(356)
|
|
Net cash provided by (used in) financing activities
|
|
(6,040)
|
(6,993)
|
(4,605)
|
|
(13,728)
|
(11,952)
|
|
Currency translation differences relating to cash and cash
equivalents
|
|
54
|
49
|
(51)
|
|
(6)
|
248
|
|
Increase (decrease) in cash and cash equivalents
|
|
5,858
|
1,468
|
(175)
|
|
6,385
|
(4,314)
|
|
Cash
and cash equivalents at beginning of period(b)
|
|
37,185
|
35,717
|
35,130
|
|
36,658
|
39,269
|
|
Cash
and cash equivalents at end of period(c)
|
|
43,043
|
37,185
|
34,955
|
|
43,043
|
34,955
|
(a)
See Condensed group
statement of changes in equity - footnote (a) for further
information.
(b)
Nine months 2026
includes the impact of initial adoption of amendments to IFRS 9
'Financial Instruments'. See note 1.
(c)
Third quarter and
nine months 2026 include $50 million (second quarter 2026 $17
million, third quarter and nine months 2025 $46 million) of cash
and cash equivalents classified as assets held for sale in the
group balance sheet.
Notes
Note 1. Basis of preparation
The
interim financial information included in this report has been
prepared in accordance with IAS 34 'Interim Financial
Reporting'.
The
results for the interim periods presented herein are unaudited and,
in the opinion of management, include all adjustments necessary for
a fair presentation of the results for each period. All such
adjustments are of a normal recurring nature. This report should be
read in conjunction with the consolidated financial statements and
related notes for the year ended 31 December 2025 included in
bp Annual Report and Form 20-F
2025.
bp
prepares its consolidated financial statements included within bp
Annual Report and Form 20-F on the basis of United Kingdom adopted
international accounting standards and IFRS® Accounting
Standards (IFRS) as issued by the International Accounting
Standards Board (IASB), IFRS as adopted by the European Union (EU),
and in accordance with the provisions of the UK Companies Act 2006
as applicable to companies reporting under international accounting
standards. IFRS as adopted by the UK does not differ from IFRS as
adopted by the EU. IFRS as adopted by the UK and EU differ in
certain respects from IFRS as issued by the IASB. The differences
have no impact on the group’s consolidated financial
statements for the periods presented. The financial information
presented herein has been prepared in accordance with the
accounting policies expected to be used in preparing bp Annual
Report and Form 20-F 2026, which are the same as those used in
preparing bp Annual Report and
Form 20-F 2025.
New standards and amendments to IFRS
On 1
January 2026, bp adopted the amendments to IFRS 9 ‘Financial
Instruments’ relating to the settlement of liabilities
through electronic payment systems using the modified retrospective
approach. The impact to the interim financial information upon
transition was a $34 million increase to cash and cash
equivalents.
Significant accounting judgements and estimates
bp's
significant accounting judgements and estimates were disclosed in
bp Annual Report and Form 20-F
2025. These have been subsequently considered at the end of
this quarter to determine if any changes were required to those
judgements and estimates.
Considerations in respect of ongoing geopolitical instability in
the Middle East and impact on the economic environment
The
impact of ongoing geopolitical instability in the Middle East and
the associated economic developments have been considered for the
basis of preparation for the interim financial information. Such
factors include the economic effect of price volatility, supply
disruptions in the region, operability of producing assets and
discount rates.
Impairment testing assumptions
As a
result of ongoing geopolitical instability in the Middle East and
the related economic impact, the group’s value-in-use
impairment testing price assumptions for Brent oil and Henry Hub
gas were revised during the third quarter from those disclosed in
the bp Annual Report and Form 20-F
2025, and also revised since the second quarter 2026. The
group has updated its estimate of Brent oil prices to $87/bbl
(previously $70/bbl) and Henry Hub gas prices to $3.18/mmBtu
(previously $3.80/mmBtu) in real 2024 terms on an average basis for
the full year 2026. With reference to the Brent price, this
estimate assumes ongoing supply disruptions resulting from
geopolitical instability in the Middle East into 2027. With regard
to the Henry Hub gas price assumption, the price decrease is based
on an expectation of strong production growth for the remainder of
2026 and into 2027 in the US domestic market. No material
impairment or reversal of impairment arose in the third quarter
2026 interim period as a result of the changes to these commodity
price assumptions. The post-tax discount rate used for value-in-use
impairment testing of assets other than certain low carbon energy
assets was maintained at 8% (31 December 2025 8%).
Segmentation
Reportable
segments for external financial reporting will remain Oil
production & operations, Gas & low carbon energy and
Customers & products until 31 December 2026, as the financial
reporting aspects of the new segment model announced on 9 June 2026
will take time to implement. Until the new reporting segments take
effect from the financial year beginning 1 January 2027, decisions
about resource allocation and performance assessment of segments
will continue to be made on the existing segmental internal
reporting regularly reviewed by the chief operating decision
maker.
Note 2. Non-current assets held for sale
The
carrying amount of assets classified as held for sale at
30 September 2026 is $9,014 million, with associated
liabilities of $3,128 million.
Gas & low carbon energy
On 24
October 2024, bp completed the acquisition of the remaining 50.03%
of Lightsource bp. The acquisition included certain assets for
which sales processes were in progress at the acquisition date. The
sales of these assets are expected to complete in 2026. The
carrying amount of assets classified as held for sale at 30
September 2026 is $856 million, with associated liabilities of
$587 million.
Oil production & operations
On 17
July 2026 bp and ConocoPhillips agreed terms for ConocoPhillips to
acquire a 42% interest in BP Energy Company of Kirkuk Limited (BP
ECKL). On 28 July 2026 bp and Türkiye Petrolleri Anonim
Ortaklığı (TPAO) agreed terms for TPAO to acquire a
15% interest in BP ECKL. The three parties intend to form a joint
venture, and bp expects to equity account for its retained 43%
interest after completion. The sales of these interests are
expected to be completed during the fourth quarter of 2026. The
carrying amount of assets classified as held for sale at 30
September 2026 is $485 million, with associated liabilities of $248
million.
Customers & products
On 18
March 2026, bp agreed with the Klesch Group to divest its 100%
interest in the Gelsenkirchen refinery and associated assets. The
transaction completed on 31 July 2026. The related assets and
liabilities, of the business, previously classified as held for
sale, were derecognised on that date. A loss on sale of businesses
of $249 million has been recognized including $345 million of
cumulative foreign exchange losses recycled to the group income
statement from reserves.
On 24
December 2025, bp announced an agreement with Stonepeak to divest a
65% shareholding in the Castrol business with bp retaining a 35%
interest through a holding in a newly incorporated entity. The
carrying amount of assets classified as held for sale at 30
September 2026 is $7,673 million including $2,707 million
of goodwill that arose on the acquisition of Castrol in 2000, with
associated liabilities of $2,293 million. See also Note
10.
Note 3. Impairment and losses on sale of businesses and fixed
assets
Net
impairment charges and losses on sale of businesses and fixed
assets for the third quarter and nine months were
$4,364 million and $6,053 million respectively, compared
with net charges of $753 million and $2,413 million for
the same periods in 2025 and include net impairment charges for the
third quarter and nine months of $4,067 million and
$5,315 million respectively, compared with net impairment
charges of $370 million and $1,931 million for
the same periods in 2025.
Gas & low carbon energy
Third
quarter and nine months 2026 impairments includes a net impairment
charge of $3,365 million and $3,890 million respectively,
primarily related to the group's transition businesses, including
Lightsource bp and offshore wind, compared with net charges of
$135 million and $881 million for the same periods in
2025 in the gas & low carbon energy segment.
Oil production & operations
Third
quarter and nine months 2026 impairments includes a charge of
$73 million and $328 million respectively, compared with
a reversal of $7 million and a net charge of $329 million
for the same periods in 2025 in the oil production & operations
segment.
Customers & products
Third
quarter and nine months 2026 impairments includes an impairment
charge of $629 million and $854 million respectively,
compared with net charges of $242 million and
$719 million for the same periods in 2025 in the customers
& products segment.
Note 4. Analysis of replacement cost profit (loss) before interest
and tax and reconciliation to profit (loss) before
taxation
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
gas & low carbon energy
|
|
208
|
1,564
|
1,097
|
|
2,826
|
3,502
|
|
oil production & operations
|
|
3,405
|
3,397
|
2,119
|
|
8,457
|
6,823
|
|
customers & products
|
|
4,796
|
5,100
|
1,610
|
|
12,348
|
2,685
|
|
other businesses & corporate
|
|
(765
|
(250
|
(277
|
|
(1,870
|
346
|
|
|
|
7,644
|
9,811
|
4,549
|
|
21,761
|
13,356
|
|
Consolidation adjustment – UPII*
|
|
—
|
—
|
(19
|
|
21
|
24
|
|
RC profit (loss) before interest and tax
|
|
7,644
|
9,811
|
4,530
|
|
21,782
|
13,380
|
|
Inventory holding gains (losses)*
|
|
|
|
|
|
|
|
|
gas
& low carbon energy
|
|
—
|
—
|
—
|
|
—
|
—
|
|
oil
production & operations
|
|
2
|
(1
|
(3
|
|
8
|
2
|
|
customers
& products
|
|
2,038
|
(869
|
(79
|
|
5,321
|
(479
|
|
Profit (loss) before interest and tax
|
|
9,684
|
8,941
|
4,448
|
|
27,111
|
12,903
|
|
Finance costs
|
|
1,120
|
1,175
|
1,267
|
|
3,470
|
3,817
|
|
Net
finance expense/(income) relating to pensions and other
post-employment benefits
|
|
(49
|
(55
|
(55
|
|
(158
|
(163
|
|
Profit (loss) before taxation
|
|
8,613
|
7,821
|
3,236
|
|
23,799
|
9,249
|
|
|
|
|
|
|
|
|
|
|
RC profit (loss) before interest and tax*
|
|
|
|
|
|
|
|
|
US
|
|
3,718
|
3,727
|
632
|
|
8,966
|
3,582
|
|
Non-US
|
|
3,926
|
6,084
|
3,898
|
|
12,816
|
9,798
|
|
|
|
7,644
|
9,811
|
4,530
|
|
21,782
|
13,380
|
Note 5. Sales and other operating revenues
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
By segment
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
14,905
|
11,675
|
9,655
|
|
36,027
|
29,605
|
|
oil production & operations
|
|
7,251
|
7,813
|
6,232
|
|
21,016
|
18,787
|
|
customers & products
|
|
53,322
|
57,159
|
38,697
|
|
153,442
|
112,309
|
|
other businesses & corporate
|
|
735
|
739
|
627
|
|
2,035
|
1,650
|
|
|
|
76,213
|
77,386
|
55,211
|
|
212,520
|
162,351
|
|
|
|
|
|
|
|
|
|
|
Less: sales and other operating revenues between
segments
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
369
|
808
|
310
|
|
1,524
|
1,378
|
|
oil production & operations
|
|
6,777
|
7,289
|
5,908
|
|
19,666
|
17,544
|
|
customers & products
|
|
254
|
(293
|
70
|
|
436
|
57
|
|
other businesses & corporate
|
|
414
|
477
|
503
|
|
1,135
|
1,420
|
|
|
|
7,814
|
8,281
|
6,791
|
|
22,761
|
20,399
|
|
|
|
|
|
|
|
|
|
|
External sales and other operating revenues
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
14,536
|
10,867
|
9,345
|
|
34,503
|
28,227
|
|
oil production & operations
|
|
474
|
524
|
324
|
|
1,350
|
1,243
|
|
customers & products
|
|
53,068
|
57,452
|
38,627
|
|
153,006
|
112,252
|
|
other businesses & corporate
|
|
321
|
262
|
124
|
|
900
|
230
|
|
Total sales and other operating revenues
|
|
68,399
|
69,105
|
48,420
|
|
189,759
|
141,952
|
|
|
|
|
|
|
|
|
|
|
By geographical area
|
|
|
|
|
|
|
|
|
US
|
|
23,504
|
25,125
|
18,968
|
|
68,105
|
56,947
|
|
Non-US
|
|
56,360
|
57,019
|
37,877
|
|
155,956
|
109,811
|
|
|
|
79,864
|
82,144
|
56,845
|
|
224,061
|
166,758
|
|
Less: sales and other operating revenues between areas
|
|
11,465
|
13,039
|
8,425
|
|
34,302
|
24,806
|
|
|
|
68,399
|
69,105
|
48,420
|
|
189,759
|
141,952
|
|
|
|
|
|
|
|
|
|
|
Revenues from contracts with customers
|
|
|
|
|
|
|
|
|
Sales
and other operating revenues include the following in relation to
revenues from contracts with customers:
|
|
|
|
|
|
|
|
|
Crude oil
|
|
347
|
402
|
635
|
|
1,082
|
1,471
|
|
Oil products
|
|
42,425
|
43,549
|
30,274
|
|
115,825
|
86,008
|
|
Natural gas, LNG and NGLs
|
|
10,681
|
8,523
|
7,192
|
|
25,841
|
20,504
|
|
Non-oil products and other revenues from contracts with
customers
|
|
3,880
|
3,721
|
3,528
|
|
11,296
|
10,858
|
|
Revenue from contracts with customers
|
|
57,333
|
56,195
|
41,629
|
|
154,044
|
118,841
|
|
Other
operating revenues(a)
|
|
11,066
|
12,910
|
6,791
|
|
35,715
|
23,111
|
|
Total sales and other operating revenues
|
|
68,399
|
69,105
|
48,420
|
|
189,759
|
141,952
|
(a)
Principally relates
to commodity derivative transactions including sales of bp own
production in trading books.
Note 6. Depreciation, depletion and amortization
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Total depreciation, depletion and amortization by
segment
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
1,228
|
1,139
|
1,223
|
|
3,553
|
3,796
|
|
oil production & operations
|
|
1,861
|
1,754
|
1,961
|
|
5,624
|
5,681
|
|
customers & products
|
|
1,001
|
1,002
|
1,045
|
|
2,967
|
3,090
|
|
other businesses & corporate
|
|
263
|
254
|
243
|
|
768
|
729
|
|
|
|
4,353
|
4,149
|
4,472
|
|
12,912
|
13,296
|
|
Total depreciation, depletion and amortization by geographical
area
|
|
|
|
|
|
|
|
|
US
|
|
1,794
|
1,721
|
1,898
|
|
5,394
|
5,531
|
|
Non-US
|
|
2,559
|
2,428
|
2,574
|
|
7,518
|
7,765
|
|
|
|
4,353
|
4,149
|
4,472
|
|
12,912
|
13,296
|
Note 7. Earnings per share and shares in issue
Basic
earnings per ordinary share (EpS) amounts are calculated by
dividing the profit (loss) for the period attributable to ordinary
shareholders by the weighted average number of ordinary shares
outstanding during the period.
The
calculation of EpS is performed separately for each discrete
quarterly period, and for the year-to-date period. As a result, the
sum of the discrete quarterly EpS amounts in any particular
year-to-date period may not be equal to the EpS amount for the
year-to-date period.
For the
diluted EpS calculation the weighted average number of shares
outstanding during the period is adjusted for the number of shares
that are potentially issuable in connection with employee
share-based payment plans using the treasury stock
method.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Results for the period
|
|
|
|
|
|
|
|
|
Profit
(loss) for the period attributable to bp shareholders
|
|
4,696
|
3,911
|
1,161
|
|
12,449
|
3,477
|
|
Less: preference dividend
|
|
—
|
1
|
—
|
|
1
|
1
|
|
Less:
(gain) loss on redemption of perpetual hybrid bonds(a)
|
|
—
|
65
|
—
|
|
65
|
—
|
|
Profit (loss) attributable to bp ordinary shareholders
|
|
4,696
|
3,845
|
1,161
|
|
12,383
|
3,476
|
|
|
|
|
|
|
|
|
|
|
Number of shares (thousand)(b)
|
|
|
|
|
|
|
|
|
Basic
weighted average number of shares outstanding
|
|
15,555,241
|
15,522,233
|
15,518,940
|
|
15,516,394
|
15,646,554
|
|
ADS
equivalent(c)
|
|
2,592,540
|
2,587,038
|
2,586,490
|
|
2,586,065
|
2,607,759
|
|
|
|
|
|
|
|
|
|
|
Weighted average
number of shares outstanding used to calculate diluted earnings per
share
|
|
15,710,351
|
15,667,335
|
15,735,029
|
|
15,716,209
|
15,968,108
|
|
ADS
equivalent(c)
|
|
2,618,391
|
2,611,222
|
2,622,504
|
|
2,619,368
|
2,661,351
|
|
|
|
|
|
|
|
|
|
|
Shares in issue at period-end
|
|
15,563,419
|
15,546,713
|
15,487,180
|
|
15,563,419
|
15,487,180
|
|
ADS
equivalent(c)
|
|
2,593,903
|
2,591,118
|
2,581,196
|
|
2,593,903
|
2,581,196
|
(a)
See Condensed group
statement of changes in equity - footnote (a) for further
information.
(b)
Excludes treasury
shares and includes certain shares that will be issued in the
future under employee share-based payment plans.
(c)
One ADS is
equivalent to six ordinary shares.
Note 8. Dividends
Dividends payable
bp
today announced an interim dividend of 8.660 cents per ordinary
share which is expected to be paid on 18 December 2026 to ordinary
shareholders and American Depositary Share (ADS) holders on the
register on 13 November 2026. The ex-dividend date will be 12
November 2026 for ordinary shareholders and 13 November 2026 for
ADS holders. The corresponding amount in sterling is due to be
announced on 8 December 2026, calculated based on the average of
the market exchange rates over three dealing days between 2
December 2026 and 4 December 2026. Holders of ADSs are expected to
receive $0.5196 per ADS (less applicable fees). The board has
decided not to offer a scrip dividend alternative in respect of the
third quarter 2026 dividend. Ordinary shareholders and ADS holders
(subject to certain exceptions) will be able to participate in a
dividend reinvestment programme. Details of the third quarter
dividend and timetable are available at bp.com/dividends and further details of
the dividend reinvestment programmes are available at bp.com/drip.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Dividends paid per ordinary share
|
|
|
|
|
|
|
|
|
cents
|
|
8.660
|
8.320
|
8.320
|
|
25.300
|
24.320
|
|
pence
|
|
6.406
|
6.184
|
6.194
|
|
18.816
|
18.270
|
|
Dividends paid per ADS (cents)
|
|
51.96
|
49.92
|
49.92
|
|
151.80
|
145.92
|
Note 9. Net debt*
|
|
|
30 September
|
30 June
|
30 September
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
Finance
debt(a)
|
|
55,366
|
58,337
|
60,188
|
|
Fair
value (asset) liability of hedges related to finance
debt(b)
|
|
1,497
|
1,082
|
775
|
|
|
|
56,863
|
59,419
|
60,963
|
|
Less: cash and cash equivalents
|
|
42,993
|
37,168
|
34,909
|
|
Net
debt(c)
|
|
13,870
|
22,251
|
26,054
|
|
Total equity
|
|
79,593
|
76,420
|
77,645
|
|
Gearing*
|
|
14.8%
|
22.6%
|
25.1%
|
(a)
The fair value of
finance debt at 30 September 2026 was $50,344 million (30 June
2026 $54,869 million, 30 September 2025 $57,113
million).
(b)
Derivative
financial instruments entered into for the purpose of managing
foreign currency exchange risk associated with net debt with a fair
value liability position of $103 million at 30 September
2026 (second quarter 2026 liability of $105 million and third
quarter 2025 liability of $94 million) are not included in the
calculation of net debt shown above as hedge accounting is not
applied for these instruments.
(c)
Net debt does not
include accrued interest, which is reported within other
receivables and other payables on the balance sheet and for which
the associated cash flows are presented as operating cash flows in
the group cash flow statement.
As part
of actively managing its debt portfolio, in the third quarter and
nine months 2026, the group bought back $1.0 billion of finance
debt consisting entirely of US dollar bonds. These transactions
have no significant impact on net debt or gearing.
Note 10. Update on bp’s sale of a 65% shareholding in the
Castrol business
On 24
December 2025, bp announced an agreement with Stonepeak to divest a
65% shareholding in the Castrol business with bp retaining a 35%
interest through a holding in a newly incorporated
entity.
The
sale is expected to complete imminently. The related assets and
liabilities of the business, previously classified as held for
sale, will be derecognised as of that date. Proceeds from the sale
of the business, net of cash disposed, are estimated to be $6
billion. The shares to be held by Stonepeak after the transaction
closes are subject to preferred distributions, the effect of which
is that bp does not expect to recognize income or dividends from
the investment in the short to medium term.
Note 11. Statutory accounts
The
financial information shown in this publication, which was approved
by the Board of Directors on 29 October 2026, is unaudited and does
not constitute statutory financial statements. Audited financial
information will be published in bp Annual Report and Form 20-F 2026. bp Annual
Report and Form 20-F 2025 has been filed with the Registrar
of Companies in England and Wales. The report of the auditor on
those accounts was unqualified, did not include a reference to any
matters to which the auditor drew attention by way of emphasis
without qualifying the report and did not contain a statement under
section 498(2) or section 498(3) of the UK Companies Act
2006.
Additional information
Capital expenditure
Capital
expenditure is a measure that provides useful information to
understand how bp’s management allocates resources including
the investment of funds in projects which expand the group’s
activities through acquisition.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Capital expenditure
|
|
|
|
|
|
|
|
|
Organic capital expenditure*
|
|
3,036
|
3,086
|
3,328
|
|
9,398
|
10,089
|
|
Inorganic capital expenditure*
|
|
—
|
—
|
53
|
|
14
|
276
|
|
|
|
3,036
|
3,086
|
3,381
|
|
9,412
|
10,365
|
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Capital expenditure by segment
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
916
|
776
|
828
|
|
2,387
|
2,521
|
|
oil production & operations
|
|
1,612
|
1,733
|
1,722
|
|
5,236
|
5,124
|
|
customers & products
|
|
483
|
538
|
770
|
|
1,678
|
2,510
|
|
other businesses & corporate
|
|
25
|
39
|
61
|
|
111
|
210
|
|
|
|
3,036
|
3,086
|
3,381
|
|
9,412
|
10,365
|
|
Capital expenditure by geographical area
|
|
|
|
|
|
|
|
|
US
|
|
1,385
|
1,423
|
1,591
|
|
4,410
|
4,600
|
|
Non-US
|
|
1,651
|
1,663
|
1,790
|
|
5,002
|
5,765
|
|
|
|
3,036
|
3,086
|
3,381
|
|
9,412
|
10,365
|
Adjusting items*
Adjusting
items are items that management considers to be important to
period-on-period analysis of the group's results and are disclosed
in order to enable investors to better understand and evaluate the
group’s reported financial performance. Adjusting items are
used as a reconciling adjustment to derive underlying RC profit or
loss and related underlying measures which are non-IFRS
measures.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
gas & low carbon energy
|
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
11
|
7
|
—
|
|
19
|
68
|
|
Net
impairment and losses on sale of businesses and fixed
assets(a)
|
|
(3,366)
|
(687)
|
(489)
|
|
(4,109)
|
(1,294)
|
|
Environmental and related provisions
|
|
—
|
—
|
—
|
|
—
|
—
|
|
Restructuring, integration and rationalization costs
|
|
(20)
|
(9)
|
8
|
|
(42)
|
(3)
|
|
Fair
value accounting effects(b)(c)
|
|
644
|
205
|
131
|
|
576
|
817
|
|
Other
|
|
(244)
|
(74)
|
(72)
|
|
(259)
|
(64)
|
|
|
|
(2,975)
|
(558)
|
(422)
|
|
(3,815)
|
(476)
|
|
oil production & operations
|
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
23
|
5
|
(29)
|
|
95
|
176
|
|
Net
impairment and losses on sale of businesses and fixed
assets
|
|
(71)
|
(108)
|
10
|
|
(334)
|
(335)
|
|
Environmental and related provisions
|
|
(44)
|
(42)
|
(145)
|
|
(256)
|
(231)
|
|
Restructuring, integration and rationalization costs
|
|
(89)
|
(9)
|
9
|
|
(164)
|
(78)
|
|
Fair value accounting effects
|
|
—
|
—
|
—
|
|
—
|
—
|
|
Other
|
|
52
|
(30)
|
(25)
|
|
20
|
(165)
|
|
|
|
(129)
|
(184)
|
(180)
|
|
(639)
|
(633)
|
|
customers & products
|
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
(18)
|
4
|
10
|
|
19
|
29
|
|
Net
impairment and losses on sale of businesses and fixed
assets(a)
|
|
(927)
|
(306)
|
(274)
|
|
(1,367)
|
(777)
|
|
Environmental and related provisions
|
|
—
|
—
|
(1)
|
|
(3)
|
(2)
|
|
Restructuring, integration and rationalization costs
|
|
(92)
|
(40)
|
(17)
|
|
(192)
|
(194)
|
|
Fair
value accounting effects(c)
|
|
(1,093)
|
641
|
42
|
|
(1,045)
|
(241)
|
|
Other
|
|
(22)
|
(153)
|
134
|
|
(169)
|
(56)
|
|
|
|
(2,152)
|
146
|
(106)
|
|
(2,757)
|
(1,241)
|
|
other businesses & corporate
|
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
2
|
—
|
2
|
|
3
|
2
|
|
Net
impairment and losses on sale of businesses and fixed
assets
|
|
—
|
1
|
—
|
|
(243)
|
(5)
|
|
Environmental and related provisions
|
|
(139)
|
(21)
|
(48)
|
|
(160)
|
(138)
|
|
Restructuring, integration and rationalization costs
|
|
9
|
(5)
|
(8)
|
|
(106)
|
(245)
|
|
Fair
value accounting effects(c)
|
|
(92)
|
114
|
(13)
|
|
(196)
|
1,096
|
|
Gulf of America oil spill
|
|
(3)
|
—
|
(9)
|
|
(7)
|
(27)
|
|
Other(d)
|
|
(320)
|
6
|
(12)
|
|
(322)
|
7
|
|
|
|
(543)
|
95
|
(88)
|
|
(1,031)
|
690
|
|
Total before interest and taxation
|
|
(5,799)
|
(501)
|
(796)
|
|
(8,242)
|
(1,660)
|
|
Finance
costs(e)
|
|
(51)
|
(67)
|
(83)
|
|
(192)
|
(348)
|
|
Total before taxation
|
|
(5,850)
|
(568)
|
(879)
|
|
(8,434)
|
(2,008)
|
|
Taxation
on adjusting items(f)(g)
|
|
490
|
(439)
|
125
|
|
(469)
|
664
|
|
Taxation
– tax rate change effect(h)
|
|
—
|
(97)
|
(233)
|
|
(97)
|
(772)
|
|
Total after taxation for period
|
|
(5,360)
|
(1,104)
|
(987)
|
|
(9,000)
|
(2,116)
|
(a)
See Note 3 for
further information.
(b)
Under IFRS bp
marks-to-market the value of the hedges used to risk-manage LNG
contracts, but not the contracts themselves, resulting in a
mismatch in accounting treatment. The fair value accounting effect
includes the change in value of LNG contracts that are being risk
managed, and the underlying result reflects how bp risk-manages its
LNG contracts.
(c)
For further
information, including the nature of fair value accounting effects
reported in each segment, see pages 4, 7
and 32.
(d)
Third quarter and
nine months 2026 include a $313 million loss on settlement of a
defined benefit pension plan in the Netherlands.
(e)
Includes the
unwinding of discounting effects relating to Gulf of America oil
spill payables, the income statement impact of temporary valuation
differences related to the group’s interest rate and foreign
currency exchange risk management associated with finance debt, and
the unwinding of discounting effects relating to certain onerous
contract provisions. Third quarter and nine months 2026 also
include the income statement impact of the buyback of finance debt
(see Note 9 for further information).
(f)
Includes certain
foreign exchange effects on tax as adjusting items. These amounts
represent the impact of: (i) foreign exchange on deferred tax
balances arising from the conversion of local currency tax base
amounts into functional currency, and (ii) taxable gains and losses
from the retranslation of US dollar-denominated intra-group loans
to local currency.
(g)
Second quarter 2026
and nine months 2026 include the impact of the reassessment of the
recognition of deferred tax assets.
(h)
Second quarter 2026
and nine months 2025 include revisions to the deferred tax impact
of the introduction of the UK Energy Profits Levy (EPL) on
temporary differences existing at the opening balance sheet date.
The EPL increases the headline rate of tax on taxable profits from
bp’s North Sea business to 78%. In the first quarter 2025 a
two-year extension of the EPL to 31 March 2030 was substantively
enacted. Third quarter 2025 and nine months 2025 include the
deferred tax impact of a change in the tax rate in
Germany.
Net debt including leases*
Gearing
including leases and net debt including leases are non-IFRS
measures that provide the impact of the group’s lease
portfolio on net debt and gearing.
|
Net debt including leases
|
|
30 September
|
30 June
|
30 September
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
Net debt*
|
|
13,870
|
22,251
|
26,054
|
|
Lease liabilities
|
|
14,250
|
14,356
|
14,629
|
|
Net
partner (receivable) payable for leases entered into on behalf of
joint operations
|
|
(966)
|
(1,040)
|
(1,082)
|
|
Net debt including leases
|
|
27,154
|
35,567
|
39,601
|
|
Total
equity
|
|
79,593
|
76,420
|
77,645
|
|
Gearing including leases*
|
|
25.4%
|
31.8%
|
33.8%
|
Gulf of America oil spill
|
|
|
30 September
|
31 December
|
|
$ million
|
|
2026
|
2025
|
|
Gulf of America oil spill payables and provisions
|
|
(5,940)
|
(7,256)
|
|
Of
which - current
|
|
(1,131)
|
(1,522)
|
|
|
|
|
|
|
Deferred tax asset
|
|
886
|
1,110
|
During
the second quarter pre-tax payments of $1,129 million were
made relating to the 2016 consent decree and settlement agreement
with the United States and the five Gulf coast states. Payables and
provisions presented in the table above reflect the latest estimate
for the remaining costs associated with the Gulf of America oil
spill. Where amounts have been provided on an estimated basis, the
amounts ultimately payable may differ from the amounts provided and
the timing of payments is uncertain. Further information relating
to the Gulf of America oil spill, including information on the
nature and expected timing of payments relating to provisions and
other payables, is provided in bp
Annual Report and Form 20-F 2025 - Financial
statements - Notes 7, 22, 23, 29, and 33.
Working capital* reconciliation
Change
in working capital adjusted for inventory holding gains/losses*,
fair value accounting effects* relating to subsidiaries and other
adjusting items is a non-IFRS measure. It represents what would
have been reported as movements in inventories and other current
and non-current assets and liabilities, if the starting point in
determining net cash provided by operating activities had been
underlying replacement cost profit rather than profit for the
period.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Movements in
inventories and other current and non-current assets and
liabilities as per condensed group cash flow statement(a)
|
|
1,428
|
(2,675)
|
494
|
|
(11,789)
|
(6,605)
|
|
Adjusted
for inventory holding gains (losses) (Note 4)
|
|
2,040
|
(870)
|
(82)
|
|
5,329
|
(477)
|
|
Adjusted for fair value accounting effects relating to
subsidiaries
|
|
(554)
|
906
|
177
|
|
(749)
|
1,690
|
|
Other
adjusting items(b)
|
|
(2,383)
|
1,623
|
322
|
|
694
|
1,569
|
|
Working
capital release (build) after adjusting for net inventory holding
gains (losses), fair value accounting effects and other adjusting
items
|
|
531
|
(1,016)
|
911
|
|
(6,515)
|
(3,823)
|
(a)
The movement in
working capital includes outflows relating to the Gulf of America
oil spill on a pre-tax basis of $7 million in the third
quarter 2026 (second quarter 2026 $1,129 million, third
quarter 2025 $5 million).
(b)
Other adjusting
items relate to the non-cash movement of US emissions obligations
carried as a provision that will be settled by allowances held as
inventory.
Underlying operating expenditure* reconciliation
Underlying
operating expenditure is a non-IFRS measure and a subset of
production and manufacturing expenses plus distribution and
administration expenses and excludes costs that are classified as
adjusting items. It represents the majority of the remaining
expenses in these line items but excludes certain costs that are
variable, primarily with volumes (such as freight
costs).
Management
believes that underlying operating expenditure is a performance
measure that provides investors with useful information regarding
the company’s financial performance because it considers
these expenses to be the principal operating and overhead expenses
that are most directly under their control although they also
include certain foreign exchange and commodity price
effects.
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
From group income statement
|
|
|
|
|
|
|
|
|
Production and manufacturing expenses
|
|
7,641
|
8,954
|
6,620
|
|
25,132
|
18,887
|
|
Distribution and administration expenses
|
|
4,894
|
4,610
|
4,271
|
|
14,130
|
12,924
|
|
|
|
12,535
|
13,564
|
10,891
|
|
39,262
|
31,811
|
|
Less certain variable costs:
|
|
|
|
|
|
|
|
|
Transportation
and shipping costs
|
|
3,244
|
3,772
|
2,579
|
|
10,099
|
7,659
|
|
Environmental
costs
|
|
1,075
|
2,917
|
1,290
|
|
6,391
|
4,257
|
|
Marketing
and distribution costs
|
|
868
|
724
|
358
|
|
2,359
|
1,206
|
|
Commission,
storage and handling costs
|
|
399
|
423
|
410
|
|
1,221
|
1,181
|
|
Other
variable costs and non-cash costs
|
|
385
|
253
|
654
|
|
1,141
|
1,386
|
|
Certain
variable costs and non-cash costs
|
|
5,971
|
8,089
|
5,291
|
|
21,211
|
15,689
|
|
|
|
|
|
|
|
|
|
|
Adjusted operating expenditure*
|
|
6,564
|
5,475
|
5,600
|
|
18,051
|
16,122
|
|
Less certain adjusting items*:
|
|
|
|
|
|
|
|
|
Gulf
of America oil spill
|
|
3
|
—
|
9
|
|
7
|
27
|
|
Environmental
and related provisions
|
|
183
|
63
|
194
|
|
419
|
371
|
|
Restructuring,
integration and rationalization costs
|
|
192
|
63
|
8
|
|
504
|
520
|
|
Fair
value accounting effects – derivative instruments relating to
the hybrid bonds
|
|
92
|
(114
|
13
|
|
196
|
(1,096)
|
|
Other
certain adjusting items(a)
|
|
830
|
130
|
(111)
|
|
959
|
52
|
|
Certain adjusting items
|
|
1,300
|
142
|
113
|
|
2,085
|
(126)
|
|
|
|
|
|
|
|
|
|
|
Underlying operating expenditure
|
|
5,264
|
5,333
|
5,487
|
|
15,966
|
16,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Decrease) increase in underlying operating
expenditure
|
|
(282)
|
|
||||
|
Of which:
|
|
|
|
|
|
|
|
|
Structural cost reduction*
|
|
|
|
|
|
(1,223)
|
|
|
Increase/(decrease) in underlying operating expenditure due to
inflation, exchange movements, portfolio changes and
growth
|
|
941
|
|
||||
|
|
|
|
|
|
|
|
|
|
Structural cost reduction at 30 September 2026 since
2023
|
|
||||||
|
Structural cost reduction in 2024 and 2025
|
|
|
|
|
|
(2,761
|
|
|
Structural cost reduction in the nine months 2026
|
|
|
|
|
|
(1,223
|
|
|
Cumulative
structural cost reduction excluding the Gelsenkirchen
refinery
|
|
|
|
|
|
(3,984)
|
|
(a)
Third quarter and
nine months 2026 include a $313 million loss on settlement of a
defined benefit pension plan in the Netherlands.
Reconciliation of customers & products RC profit before
interest and tax to underlying RC profit before interest and tax*
to adjusted EBITDA* by business
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
RC profit before interest and tax for customers &
products
|
|
4,796
|
5,100
|
1,610
|
|
12,348
|
2,685
|
|
Less: Adjusting items* gains (charges)
|
|
(2,152)
|
146
|
(106)
|
|
(2,757)
|
(1,241)
|
|
Underlying
RC profit before interest and tax for customers &
products
|
|
6,948
|
4,954
|
1,716
|
|
15,105
|
3,926
|
|
By business:
|
|
|
|
|
|
|
|
|
customers
– convenience & mobility
|
|
1,223
|
1,771
|
1,167
|
|
4,003
|
2,887
|
|
Castrol – included in customers
|
|
285
|
429
|
261
|
|
1,060
|
744
|
|
products
– refining & trading
|
|
5,725
|
3,183
|
549
|
|
11,102
|
1,039
|
|
|
|
|
|
|
|
|
|
|
Add back: Depreciation, depletion and amortization
|
|
1,001
|
1,002
|
1,045
|
|
2,967
|
3,090
|
|
By business:
|
|
|
|
|
|
|
|
|
customers
– convenience & mobility
|
|
573
|
569
|
619
|
|
1,674
|
1,828
|
|
Castrol – included in customers
|
|
—
|
—
|
48
|
|
—
|
144
|
|
products
– refining & trading
|
|
428
|
433
|
426
|
|
1,293
|
1,262
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA for customers & products
|
|
7,949
|
5,956
|
2,761
|
|
18,072
|
7,016
|
|
By business:
|
|
|
|
|
|
|
|
|
customers
– convenience & mobility
|
|
1,796
|
2,340
|
1,786
|
|
5,677
|
4,715
|
|
Castrol – included in customers
|
|
285
|
429
|
309
|
|
1,060
|
888
|
|
products
– refining & trading
|
|
6,153
|
3,616
|
975
|
|
12,395
|
2,301
|
Realizations and marker prices
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
Average realizations(a)
|
|
|
|
|
|
|
|
|
Liquids(b)
($/bbl)
|
|
|
|
|
|
|
|
|
US
|
|
67.31
|
76.03
|
54.02
|
|
64.60
|
56.32
|
|
Europe
|
|
102.74
|
97.49
|
69.15
|
|
94.59
|
69.81
|
|
Rest of World
|
|
88.04
|
95.39
|
67.20
|
|
84.26
|
70.36
|
|
bp average
|
|
77.20
|
85.14
|
60.02
|
|
74.11
|
62.55
|
|
Natural gas ($/mcf)
|
|
|
|
|
|
|
|
|
US
|
|
2.41
|
1.72
|
2.41
|
|
2.48
|
2.67
|
|
Europe
|
|
16.89
|
17.25
|
11.98
|
|
13.95
|
13.90
|
|
Rest of World
|
|
8.61
|
8.03
|
6.41
|
|
7.64
|
6.71
|
|
bp
average
|
|
6.57
|
5.89
|
5.34
|
|
5.95
|
5.75
|
|
Total hydrocarbons ($/boe)
|
|
|
|
|
|
|
|
|
US
|
|
45.54
|
48.47
|
38.91
|
|
44.30
|
41.41
|
|
Europe
|
|
102.08
|
97.85
|
69.25
|
|
92.70
|
73.19
|
|
Rest of World
|
|
61.76
|
64.34
|
47.62
|
|
57.76
|
49.70
|
|
bp average
|
|
56.16
|
58.62
|
45.00
|
|
53.30
|
47.58
|
|
Average oil marker prices ($/bbl)
|
|
|
|
|
|
|
|
|
Brent
|
|
96.99
|
103.85
|
69.13
|
|
93.92
|
70.93
|
|
West Texas Intermediate
|
|
86.08
|
93.11
|
65.07
|
|
84.06
|
66.74
|
|
Western Canadian Select
|
|
66.45
|
72.86
|
52.52
|
|
65.47
|
54.66
|
|
Alaska North Slope
|
|
87.84
|
103.05
|
70.07
|
|
89.53
|
71.54
|
|
Average natural gas marker prices
|
|
|
|
|
|
|
|
|
Henry
Hub gas price(c) ($/mmBtu)
|
|
2.96
|
2.90
|
3.07
|
|
3.64
|
3.39
|
|
UK Gas – National Balancing Point (p/therm)
|
|
155.75
|
112.39
|
79.84
|
|
123.46
|
93.38
|
(a)
Based on sales of
consolidated subsidiaries only – this excludes equity-accounted
entities.
(b)
Liquids comprises
crude oil, condensate and natural gas liquids.
(c)
Henry Hub First of
Month Index.
Exchange rates
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
|
|
2026
|
2026
|
2025
|
|
2026
|
2025
|
|
$/£ average rate for the period
|
|
1.34
|
1.34
|
1.35
|
|
1.34
|
1.31
|
|
$/£ period-end rate
|
|
1.32
|
1.32
|
1.34
|
|
1.32
|
1.34
|
|
|
|
|
|
|
|
|
|
|
$/€ average rate for the period
|
|
1.15
|
1.16
|
1.17
|
|
1.16
|
1.12
|
|
$/€ period-end rate
|
|
1.13
|
1.14
|
1.17
|
|
1.13
|
1.17
|
|
|
|
|
|
|
|
|
|
|
$/AUD average rate for the period
|
|
0.71
|
0.71
|
0.65
|
|
0.70
|
0.64
|
|
$/AUD period-end rate
|
|
0.70
|
0.69
|
0.66
|
|
0.70
|
0.66
|
|
|
|
|
|
|
|
|
|
Legal proceedings
The
following discussion sets out the material developments in the
group’s material legal proceedings following the publication
of bp’s second quarter and first half 2026
results.
For a
full discussion of the group’s material legal proceedings,
see pages 236-237 of bp Annual
Report and Form 20-F 2025.
Louisiana Costal restoration
bp has
reached agreement to settle all remaining governmental land loss
claims brought by the coastal Louisiana parishes and the State of
Louisiana to which bp entities are named defendants. The terms of
the agreement are confidential to the parties but are not expected
to have a significant effect on the company’s financial
position or profitability.
bp
entities remain as defendants in two private landowner cases which
have been filed in Louisiana state courts seeking restoration
damages related to alleged impacts to their marshlands associated
with historic oil field operations. These cases are not expected to
have a significant effect on the company’s financial position
or profitability and in future reports bp will not report on these
proceedings absent any material developments.
Glossary
Non-IFRS
measures are provided for investors because they are closely
tracked by management to evaluate bp’s operating performance
and to make financial, strategic and operating decisions. Non-IFRS
measures are sometimes referred to as alternative performance
measures.
Adjusted EBITDA is a non-IFRS measure presented for bp's
operating segments and is defined as replacement cost (RC) profit
before interest and tax, adjusting for net adjusting items* before
interest and tax, and adding back depreciation, depletion and
amortization and exploration write-offs (net of adjusting items).
Adjusted EBITDA by business is a further analysis of adjusted
EBITDA for the customers & products businesses. bp believes it
is helpful to disclose adjusted EBITDA by operating segment and by
business because it reflects how the segments measure underlying
business delivery. The nearest equivalent measure on an IFRS basis
for the segment is RC profit or loss before interest and tax, which
is bp's measure of profit or loss that is required to be disclosed
for each operating segment under IFRS. A reconciliation to IFRS
information is provided on page 29 for the customers & products
businesses.
Adjusted operating expenditure is a non-IFRS measure and a
subset of production and manufacturing expenses plus distribution
and administration expenses. It represents the majority of the
remaining expenses in these line items but excludes certain costs
that are variable, primarily with volumes (such as freight costs).
Other variable costs are included in purchases in the income
statement. Management believes that adjusted operating expenditure
is a performance measure that provides investors with useful
information regarding the company’s financial performance
because it considers these expenses to be the principal operating
and overhead expenses that are most directly under their control
although they also include certain adjusting items*, foreign
exchange and commodity price effects. The nearest IFRS measures are
production and manufacturing expenses and distributions and
administration expenses. A reconciliation of production and
manufacturing expenses plus distribution and administration
expenses to adjusted operating expenditure is provided on page
28.
Adjusting items are items that bp discloses separately
because it considers such disclosures to be meaningful and relevant
to investors. They are items that management considers to be
important to period-on-period analysis of the group's results and
are disclosed in order to enable investors to better understand and
evaluate the group’s reported financial performance.
Adjusting items include gains and losses on the sale of businesses
and fixed assets, impairments, environmental and related provisions
and charges, restructuring, integration and rationalization costs,
fair value accounting effects and costs relating to the Gulf of
America oil spill and other items. Adjusting items within
equity-accounted earnings are reported net of incremental income
tax reported by the equity-accounted entity. Adjusting items are
used as a reconciling adjustment to derive underlying RC profit or
loss and related underlying measures which are non-IFRS measures.
An analysis of adjusting items by segment and type is shown on page
26.
Capital expenditure is total cash capital expenditure as
stated in the condensed group cash flow statement. Capital
expenditure for the operating segments, gas & low carbon energy
businesses and customers & products businesses is presented on
the same basis.
Consolidation adjustment – UPII is unrealized profit
in inventory arising on inter-segment transactions.
Divestment proceeds are disposal proceeds as per the
condensed group cash flow statement.
Glossary (continued)
Fair value accounting effects are non-IFRS adjustments to
our IFRS profit (loss). They reflect the difference between the way
bp manages the economic exposure and internally measures
performance of certain activities and the way those activities are
measured under IFRS. Fair value accounting effects are included
within adjusting items. They relate to certain of the group's
commodity, interest rate and currency risk exposures as detailed
below. Other than as noted below, the fair value accounting effects
described are reported in both the gas & low carbon energy and
customer & products segments.
bp uses
derivative instruments to manage the economic exposure relating to
inventories above normal operating requirements of crude oil,
natural gas and petroleum products. Under IFRS, these inventories
are recorded at historical cost. The related derivative
instruments, however, are required to be recorded at fair value
with gains and losses recognized in the income statement. This is
because hedge accounting is either not permitted or not followed,
principally due to the impracticality of effectiveness-testing
requirements. Therefore, measurement differences in relation to
recognition of gains and losses occur. Gains and losses on these
inventories, other than net realizable value provisions, are not
recognized until the commodity is sold in a subsequent accounting
period. Gains and losses on the related derivative commodity
contracts are recognized in the income statement, from the time the
derivative commodity contract is entered into, on a fair value
basis using forward prices consistent with the contract
maturity.
bp
enters into physical commodity contracts to meet certain business
requirements, such as the purchase of crude for a refinery or the
sale of bp’s gas production. Under IFRS these physical
contracts are treated as derivatives and are required to be fair
valued when they are managed as part of a larger portfolio of
similar transactions. Gains and losses arising are recognized in
the income statement from the time the derivative commodity
contract is entered into.
IFRS
require that inventory held for trading is recorded at its fair
value using period-end spot prices, whereas any related derivative
commodity instruments are required to be recorded at values based
on forward prices consistent with the contract maturity. Depending
on market conditions, these forward prices can be either higher or
lower than spot prices, resulting in measurement
differences.
bp
enters into contracts for pipelines and other transportation,
storage capacity, oil and gas processing, liquefied natural gas
(LNG) and certain gas and power contracts that, under IFRS, are
recorded on an accruals basis. These contracts are risk-managed
using a variety of derivative instruments that are fair valued
under IFRS. This results in measurement differences in relation to
recognition of gains and losses.
The way
that bp manages the economic exposures described above, and
measures performance internally, differs from the way these
activities are measured under IFRS. bp calculates this difference
for consolidated entities by comparing the IFRS result with
management’s internal measure of performance. We believe that
disclosing management’s estimate of this difference provides
useful information for investors because it enables investors to
see the economic effect of these activities as a
whole.
These
include:
●
Under
management’s internal measure of performance the inventory,
transportation and capacity contracts in question are valued based
on fair value using relevant forward prices prevailing at the end
of the period.
●
Fair value
accounting effects also include changes in the fair value of the
near-term portions of LNG contracts that fall within bp’s
risk management framework. LNG contracts are not considered
derivatives, because there is insufficient market liquidity, and
they are therefore accrual accounted under IFRS. However, oil and
natural gas derivative financial instruments used to risk manage
the near-term portions of the LNG contracts are fair valued under
IFRS. The fair value accounting effect, which is reported in the
gas and low carbon energy segment, represents the change in value
of LNG contracts that are being risk managed and which is reflected
in the underlying result, but not in reported earnings. Management
believes that this gives a better representation of performance in
each period.
Furthermore,
the fair values of derivative instruments used to risk manage
certain other oil, gas, power and other contracts, are deferred to
match with the underlying exposure. The commodity contracts for
business requirements are accounted for on an accruals
basis.
In
addition, fair value accounting effects include changes in the fair
value of derivatives entered into by the group to manage currency
exposure and interest rate risks relating to hybrid bonds to their
respective first call periods. The hybrid bonds which are
classified as equity instruments were recorded in the balance sheet
at their issuance date at their USD equivalent issued value. Under
IFRS these equity instruments are not remeasured from period to
period, and do not qualify for application of hedge accounting. The
derivative instruments relating to the hybrid bonds, however, are
required to be recorded at fair value with mark to market gains and
losses recognized in the income statement. Therefore,
measurement differences in relation to the recognition of gains and
losses occur. The fair value accounting effect, which is reported
in the other businesses & corporate segment, eliminates the
fair value gains and losses of these derivative financial
instruments that are recognized in the income statement. We
believe that this gives a better representation of performance, by
more appropriately reflecting the economic effect of these risk
management activities, in each period.
Glossary (continued)
Gas & low carbon energy segment comprises our gas and
low carbon businesses. Our gas business includes regions with
upstream activities that predominantly produce natural gas, gas
trading and our Archaea Energy business. Our low carbon business
includes solar, offshore wind, hydrogen and CCS, and power trading,
and until December 2025 also included onshore wind. Power trading
and marketing includes trading of both renewable and non-renewable
power.
Gearing and gearing including leases are non-IFRS measures.
See Net debt or net debt including leases below.
Hydrocarbons –
Liquids and natural gas. Natural gas is converted to oil equivalent
at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital
expenditure on a cash basis and a non-IFRS measure. Inorganic
capital expenditure comprises consideration in business
combinations and certain other significant investments made by the
group. It is reported on a cash basis. bp believes that this
measure provides useful information as it allows investors to
understand how bp’s management invests funds in projects
which expand the group’s activities through acquisition. The
nearest equivalent measure on an IFRS basis is capital expenditure
on a cash basis. Further information and a reconciliation to IFRS
information is provided on page 25.
Inventory holding gains and losses are non-IFRS adjustments
to our IFRS profit (loss) and represent:
●
the difference
between the cost of sales calculated using the replacement cost of
inventory and the cost of sales calculated on the first-in
first-out (FIFO) method after adjusting for any changes in
provisions where the net realizable value of the inventory is lower
than its cost. Under the FIFO method, which we use for IFRS
reporting of inventories other than for trading inventories, the
cost of inventory charged to the income statement is based on its
historical cost of purchase or manufacture, rather than its
replacement cost. In volatile energy markets, this can have a
significant distorting effect on reported income. The amounts
disclosed as inventory holding gains and losses represent the
difference between the charge to the income statement for inventory
on a FIFO basis (after adjusting for any related movements in net
realizable value provisions) and the charge that would have arisen
based on the replacement cost of inventory. For this purpose, the
replacement cost of inventory is calculated using data from each
operation’s production and manufacturing system, either on a
monthly basis, or separately for each transaction where the system
allows this approach; and
●
an adjustment
relating to certain trading inventories that are not price risk
managed which relate to a minimum inventory volume that is required
to be held to maintain underlying business activities. This
adjustment represents the movement in fair value of the inventories
due to prices, on a grade by grade basis, during the period. This
is calculated from each operation’s inventory management
system on a monthly basis using the discrete monthly movement in
market prices for these inventories.
The
amounts disclosed are not separately reflected in the financial
statements as a gain or loss. No adjustment is made in respect of
the cost of inventories held as part of a trading position and
certain other temporary inventory positions that are price
risk-managed. See Replacement cost (RC) profit or loss definition
below.
Liquids – Liquids comprises crude oil, condensate and
natural gas liquids. For the oil production & operations
segment, it also includes bitumen.
Major projects have a bp net investment of at least $250
million, or are considered to be of strategic importance to bp or
of a high degree of complexity.
Net debt and gearing are non-IFRS measures. Net debt is
calculated as finance debt, as shown in the balance sheet, plus the
fair value of associated derivative financial instruments that are
used to hedge foreign currency exchange and interest rate risks
relating to finance debt, for which hedge accounting is applied,
less cash and cash equivalents. Net debt does not include accrued
interest, which is reported within other receivables and other
payables on the balance sheet and for which the associated cash
flows are presented as operating cash flows in the group cash flow
statement. Gearing is defined as the ratio of net debt to the total
of net debt plus total equity. bp believes these measures provide
useful information to investors. Net debt enables investors to see
the economic effect of finance debt, related hedges and cash and
cash equivalents in total. Gearing enables investors to see how
significant net debt is relative to total equity. The derivatives
are reported on the balance sheet within the headings
‘Derivative financial instruments’. The nearest
equivalent measures on an IFRS basis are finance debt and finance
debt ratio. A reconciliation of finance debt to net debt is
provided on page 24.
We are
unable to present reconciliations of forward-looking information
for net debt or gearing to finance debt and total equity, because
without unreasonable efforts, we are unable to forecast accurately
certain adjusting items required to present a meaningful comparable
IFRS forward-looking financial measure. These items include fair
value asset (liability) of hedges related to finance debt and cash
and cash equivalents, that are difficult to predict in advance in
order to include in an IFRS estimate.
Net debt including leases and gearing including leases are
non-IFRS measures. Net debt including leases is calculated as net
debt plus lease liabilities, less the net amount of partner
receivables and payables relating to leases entered into on behalf
of joint operations. Gearing including leases is defined as the
ratio of net debt including leases to the total of net debt
including leases plus total equity. bp believes these measures
provide useful information to investors as they enable investors to
understand the impact of the group’s lease portfolio on net
debt and gearing. The nearest equivalent measures on an IFRS basis
are finance debt and finance debt ratio. A reconciliation of
finance debt to net debt including leases is provided on page
27.
Glossary (continued)
Operating cash flow is
net cash provided by (used in) operating activities as stated in
the condensed group cash flow statement.
Organic capital expenditure is a non-IFRS measure. Organic
capital expenditure comprises capital expenditure on a cash basis
less inorganic capital expenditure. bp believes that this measure
provides useful information as it allows investors to understand
how bp’s management invests funds in developing and
maintaining the group’s assets. The nearest equivalent
measure on an IFRS basis is capital expenditure on a cash basis and
a reconciliation to IFRS information is provided on page
25.
We are
unable to present reconciliations of forward-looking information
for organic capital expenditure to total cash capital expenditure,
because without unreasonable efforts, we are unable to forecast
accurately the adjusting item, inorganic capital expenditure, that
is difficult to predict in advance in order to derive the nearest
IFRS estimate.
Production-sharing agreement/contract (PSA/PSC) is an
arrangement through which an oil and gas company bears the risks
and costs of exploration, development and production. In return, if
exploration is successful, the oil company receives entitlement to
variable physical volumes of hydrocarbons, representing recovery of
the costs incurred and a stipulated share of the production
remaining after such cost recovery.
Realizations are the result of dividing revenue generated
from hydrocarbon sales, excluding revenue generated from purchases
made for resale and royalty volumes, by revenue generating
hydrocarbon production volumes. Revenue generating hydrocarbon
production reflects the bp share of production as adjusted for any
production which does not generate revenue. Adjustments may include
losses due to shrinkage, amounts consumed during processing, and
contractual or regulatory host committed volumes such as royalties.
For the gas & low carbon energy and oil production &
operations segments, realizations include transfers between
businesses.
Refining availability represents
Solomon Associates’ operational availability for bp-operated
refineries, which is defined as the percentage of the year that a
unit is available for processing after subtracting the annualized
time lost due to turnaround activity and all mechanical, process
and regulatory downtime.
Refining indicator margin (RIM) is a simple indicator of the
weighted average of bp’s crude slate and product yield as
deemed representative for each refinery. Actual margins realized by
bp may vary due to a variety of factors, including the actual mix
of a crude and product for a given quarter.
Replacement cost (RC) profit or loss / RC profit or loss
attributable to bp shareholders reflects the replacement
cost of inventories sold in the period and is calculated as profit
or loss attributable to bp shareholders, adjusting for inventory
holding gains and losses (net of tax). RC profit or loss for the
group is not a recognized IFRS measure. bp believes this measure is
useful to illustrate to investors the fact that crude oil and
product prices can vary significantly from period to period and
that the impact on our reported result under IFRS can be
significant. Inventory holding gains and losses vary from period to
period due to changes in prices as well as changes in underlying
inventory levels. In order for investors to understand the
operating performance of the group excluding the impact of price
changes on the replacement of inventories, and to make comparisons
of operating performance between reporting periods, bp’s
management believes it is helpful to disclose this measure. The
nearest equivalent measure on an IFRS basis is profit or loss
attributable to bp shareholders. A reconciliation to IFRS
information is provided on page 1. RC profit or loss before interest and
tax is bp's measure of profit or loss that is required to be
disclosed for each operating segment under IFRS.
Structural cost reduction is calculated as decreases in
underlying operating expenditure* (as defined on page 35) as a result of operational
efficiencies, divestments, workforce reductions and other cost
saving measures that are expected to be sustainable compared with
2023 levels. The total change between periods in underlying
operating expenditure will reflect both structural cost reductions
and other changes in spend, including market factors, such as
inflation and foreign exchange impacts, as well as changes in
activity levels and costs associated with new operations. Estimates
of cumulative annual structural cost reduction may be revised
depending on whether cost reductions realized in prior periods are
determined to be sustainable compared with 2023 levels. Structural
cost reductions are stewarded internally to support
management’s oversight of spending over time.
bp
believes this performance measure is useful in demonstrating how
management drives cost discipline across the entire organization,
simplifying our processes and portfolio and streamlining the way we
work. The nearest IFRS measures are production and manufacturing
expenses and distributions and administration expenses. A
reconciliation of production and manufacturing expenses plus
distribution and administration expenses to underlying operating
expenditure is provided on page 28.
Glossary (continued)
Technical service contract (TSC) – Technical service
contract is an arrangement through which an oil and gas company
bears the risks and costs of exploration, development and
production. In return, the oil and gas company receives entitlement
to variable physical volumes of hydrocarbons, representing recovery
of the costs incurred and a profit margin which reflects
incremental production added to the oilfield.
Tier 1 and tier 2 process safety events – Tier 1
events are losses of primary containment from a process of greatest
consequence – causing harm to a member of the workforce,
damage to equipment from a fire or explosion, a community impact or
exceeding defined quantities. Tier 2 events are those of lesser
consequence. These represent reported incidents occurring within
bp’s operational HSSE reporting boundary. That boundary
includes bp’s own operated facilities and certain other
locations or situations. Reported process safety events are
investigated throughout the year and as a result there may be
changes in previously reported events. Therefore comparative
movements are calculated against internal data reflecting the final
outcomes of such investigations, rather than the previously
reported comparative period, as this represents a more up to date
reflection of the safety environment.
Underlying effective tax rate (ETR) is a non-IFRS measure.
The underlying ETR is calculated by dividing taxation on an
underlying replacement cost (RC) basis by underlying RC profit or
loss before tax. Taxation on an underlying RC basis for the group
is calculated as taxation as stated on the group income statement
adjusted for taxation on inventory holding gains and losses and
total taxation on adjusting items. Information on underlying RC
profit or loss is provided below. Taxation on an underlying RC
basis presented for the operating segments is calculated through an
allocation of taxation on an underlying RC basis to each segment.
bp believes it is helpful to disclose the underlying ETR because
this measure may help investors to understand and evaluate, in the
same manner as management, the underlying trends in bp’s
operational performance on a comparable basis, period on period.
Taxation on an underlying RC basis and underlying ETR are non-IFRS
measures. The nearest equivalent measure on an IFRS basis is the
ETR on profit or loss for the period.
We are
unable to present reconciliations of forward-looking information
for underlying ETR to ETR on profit or loss for the period, because
without unreasonable efforts, we are unable to forecast accurately
certain adjusting items required to present a meaningful comparable
IFRS forward-looking financial measure. These items include the
taxation on inventory holding gains and losses and adjusting items,
that are difficult to predict in advance in order to include in an
IFRS estimate.
Underlying operating expenditure is a non-IFRS measure and a
subset of production and manufacturing expenses plus distribution
and administration expenses and excludes costs that are classified
as adjusting items. It represents the majority of the remaining
expenses in these line items but excludes certain costs that are
variable, primarily with volumes (such as freight costs). Other
variable costs are included in purchases in the income statement.
Management believes that underlying operating expenditure is a
performance measure that provides investors with useful information
regarding the company’s financial performance because it
considers these expenses to be the principal operating and overhead
expenses that are most directly under their control although they
also include certain foreign exchange and commodity price effects.
The nearest IFRS measures are production and manufacturing expenses
and distribution and administration expenses. A reconciliation of
production and manufacturing expenses plus distribution and
administration expenses to underlying operating expenditure is
provided on page 28.
Underlying production – 2026 underlying production,
when compared with 2025, is production after adjusting for
acquisitions and divestments, curtailments, and entitlement impacts
in our production-sharing agreements/contracts and technical
service contract.
Underlying RC profit or loss / underlying RC profit or loss
attributable to bp shareholders is a non-IFRS measure and is
RC profit or loss* (as defined on page 34) after excluding net adjusting items and
related taxation. See page 26
for additional information on the adjusting items that are used to
arrive at underlying RC profit or loss in order to enable a full
understanding of the items and their financial impact.
Underlying RC profit or loss before interest and tax for the
operating segments or customers & products businesses is
calculated as RC profit or loss (as defined above) including profit
or loss attributable to non-controlling interests before interest
and tax for the operating segments and excluding net adjusting
items for the respective operating segment or
business.
bp
believes that underlying RC profit or loss is a useful measure for
investors because it is a measure closely tracked by management to
evaluate bp’s operating performance and to make financial,
strategic and operating decisions and because it may help investors
to understand and evaluate, in the same manner as management, the
underlying trends in bp’s operational performance on a
comparable basis, period on period, by adjusting for the effects of
these adjusting items. The nearest equivalent measure on an IFRS
basis for the group is profit or loss attributable to bp
shareholders. The nearest equivalent measure on an IFRS basis for
segments and businesses is RC profit or loss before interest and
taxation. A reconciliation to IFRS information is provided on page
1 for the group and pages 7-13
for the segments.
Glossary (continued)
Underlying RC profit or loss per share / underlying RC profit or
loss per ADS is a non-IFRS measure. Earnings per share is
defined in Note 7. Underlying RC profit or loss per ordinary share
is calculated using the same denominator as earnings per share as
defined in the consolidated financial statements. The numerator
used is underlying RC profit or loss attributable to bp
shareholders, rather than profit or loss attributable to bp
ordinary shareholders. Underlying RC profit or loss per ADS is
calculated as outlined above for underlying RC profit or loss per
share except the denominator is adjusted to reflect one ADS
equivalent to six ordinary shares. bp believes it is helpful to
disclose the underlying RC profit or loss per ordinary share and
per ADS because these measures may help investors to understand and
evaluate, in the same manner as management, the underlying trends
in bp’s operational performance on a comparable basis, period
on period. The nearest equivalent measure on an IFRS basis is basic
earnings per share based on profit or loss for the period
attributable to bp ordinary shareholders.
upstream includes oil and natural gas field development and
production within the gas & low carbon energy and oil
production & operations segments.
upstream/hydrocarbon plant reliability (bp-operated) is
calculated taking 100% less the ratio of total unplanned plant
deferrals divided by installed production capacity, excluding
non-operated assets and bpx energy. Unplanned plant deferrals are
associated with the topside plant and where applicable the subsea
equipment (excluding wells and reservoir). Unplanned plant
deferrals include breakdowns, which does not include Gulf of
America weather related downtime.
upstream unit production costs are calculated as production
cost divided by units of production. Production cost does not
include ad valorem and severance taxes. Units of production are
barrels for liquids and thousands of cubic feet for gas. Amounts
disclosed are for bp subsidiaries only and do not include
bp’s share of equity-accounted entities.
Working capital is movements in inventories and other
current and non-current assets and liabilities as reported in the
condensed group cash flow statement.
Change
in working capital adjusted for inventory holding gains/losses,
fair value accounting effects relating to subsidiaries and other
adjusting items is a non-IFRS measure. It is calculated by
adjusting for inventory holding gains/losses reported in the
period; fair value accounting effects relating to subsidiaries
reported within adjusting items for the period; and other adjusting
items relating to the non-cash movement of US emissions obligations
carried as a provision that will be settled by allowances held as
inventory. This represents what would have been reported as
movements in inventories and other current and non-current assets
and liabilities, if the starting point in determining net cash
provided by operating activities had been underlying replacement
cost profit rather than profit for the period. The nearest
equivalent measure on an IFRS basis for this is movements in
inventories and other current and non-current assets and
liabilities.
bp
utilizes various arrangements in order to manage its working
capital including discounting of receivables and, in the supply and
trading business, the active management of supplier payment terms,
inventory and collateral.
Trade marks
Trade
marks of the bp group appear throughout this announcement. They
include: bp,
Amoco, Aral, ampm, bp pulse, Castrol, PETRO, TA, and Thorntons
Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the
United States Private Securities Litigation Reform Act of 1995 (the
‘PSLRA’) and the general doctrine of cautionary
statements, bp is providing the following cautionary
statement:
The discussion in this announcement contains certain forecasts,
projections and forward-looking statements - that is, statements
related to future, not past events and circumstances - with respect
to the financial condition, results of operations and businesses of
bp and certain of the plans and objectives of bp with respect to
these items. These statements may generally, but not always, be
identified by the use of words such as ‘will’,
‘expects’, ‘is expected to’,
‘aims’, ‘should’, ‘may’,
‘objective’, ‘is likely to’,
‘intends’, ‘believes’,
‘anticipates’, ‘plans’, ‘we
see’, ‘focus on’ or similar
expressions.
In particular, the following, among other statements, are all
forward-looking in nature: plans, expectations and assumptions
regarding oil and gas demand, supply, prices or volatility;
expectations regarding production and volumes; expectations
regarding turnaround and maintenance activity; plans and
expectations regarding bp’s balance sheet, financial
performance, strategy, four primary and other financial and
performance targets, results of operations, cost reduction, cash
flows, shareholder returns, governance and organizational
structure; plans and expectations regarding the amount and timing
of dividends and dividend reinvestment programs; plans and
expectations regarding bp’s strategy and outlook update on 15
December 2026, including bp’s longer-term plans, capital
frame, performance metrics and targets, and plans to build a
simpler, stronger and more valuable bp; plans and expectations
regarding bp’s upstream production, including the impact of
conditions in the Middle East, bp’s divestment of Culzean gas
field and bp’s reduced equity interest in Latin America;
plans and expectations regarding the amount, effects, timing,
quantum and nature of certain acquisitions, divestments and related
payments and proceeds, including expectations regarding the Castrol
business, the Austrian mobility & convenience business,
Lightsource bp, the North Sea business, the Archaea business and
other bp businesses and assets subject to disposal or divestment;
plans and expectations regarding bp’s partnerships and joint
ventures as well as current and future projects, including BP
Energy Company of Kirkuk Limited, Block TTDAA 14 (the Calypso gas
project), agreements with the government of Venezuela relating to
offshore gas development including Phase 2 of the Loran field,
Block 5(b), the Browse project, bp’s bid in the BBG-3 Gulf of
America lease sale, the Skarv Satellite Project, the Tupinamba
exploration block, the Conifer exploration prospect, the Absheron
field and Channel Infrastructure; plans and expectations regarding
bp’s net debt, credit rating, hybrid capital, investment
strategy, capital expenditures, capital frame, underlying effective
tax rate, depreciation, depletion and amortization; plans and
expectations regarding bp’s customers business, including
with respect to volumes, underlying operating expenditure, earnings
growth, cash flows, midstream performance, fuels margins, the
impact of base oil costs and conditions in the Middle East,
structural cost reduction and the earnings impact of divestments;
expectations regarding bp’s products, including underlying
performance, refining margins, maintenance activity, and refinery
turnaround activity; expectations regarding bp’s income taxes
payable, including the impact of higher profits on instalment
payments; expectations regarding bp’s other businesses &
corporate underlying annual charge; expectations regarding price
assumptions used in accounting estimates; and plans and
expectations regarding Gulf of America settlement payments,
including bp’s agreement to accelerate remaining payments to
the State of Louisiana and bp’s intention to prioritize
excess cashflow to address other remaining settlement agreement
liabilities in full.
By their nature, forward-looking statements involve risk and
uncertainty because they relate to events and depend on
circumstances that will or may occur in the future and are outside
the control of bp. Recent global developments have caused
significant uncertainty and volatility in macroeconomic conditions
and commodity markets. Each item of outlook and guidance set out in
this announcement is based on bp’s current expectations but
actual outcomes and results may be impacted by these evolving
macroeconomic and market conditions. Actual results or outcomes may
differ materially from those expressed in such statements,
depending on a variety of factors, including: the extent and
duration of the impact of current market conditions including the
volatility of oil prices, the effects of bp’s plan to exit
its shareholding in Rosneft and other investments in Russia,
overall global economic and business conditions impacting
bp’s business and demand for bp’s products as well as
the specific factors identified in the discussions accompanying
such forward-looking statements; changes in consumer preferences
and societal expectations; the pace of development and adoption of
alternative energy solutions; developments in policy, law,
regulation, technology and markets, including societal and investor
sentiment related to the issue of climate change; the receipt of
relevant third party and/or regulatory approvals including ongoing
approvals required for the continued developments of approved
projects; the timing and level of maintenance and/or turnaround
activity; the timing and volume of refinery additions and outages;
the timing of bringing new fields onstream; the timing, quantum and
nature of certain acquisitions and divestments; future levels of
industry product supply, demand and pricing, including supply
growth in North America and continued base oil and additive supply
shortages; OPEC+ quota restrictions; PSA and TSC effects;
operational and safety problems; potential lapses in product
quality; economic and financial market conditions generally or in
various countries and regions; political stability and economic
growth in relevant areas of the world; changes in laws and
governmental regulations and policies, including related to climate
change; changes in social attitudes and customer preferences;
regulatory or legal actions including the types of enforcement
action pursued and the nature of remedies sought or imposed; the
actions of prosecutors, regulatory authorities and courts; delays
in the processes for resolving claims; amounts ultimately payable
and timing of payments relating to the Gulf of America oil spill;
the conditions and developments in the Middle East; exchange rate
fluctuations; development and use of new technology; recruitment
and retention of a skilled workforce; the success or otherwise of
partnering; the actions of competitors, trading partners,
contractors, subcontractors, creditors, rating agencies and others;
bp’s access to future credit resources; business disruption
and crisis management; the impact on bp’s reputation of
ethical misconduct and non-compliance with regulatory obligations;
trading losses; major uninsured losses; the possibility that
international sanctions or other steps taken by governmental
authorities or any other relevant persons may impact bp’s
ability to sell its interests in Rosneft, or the price for which bp
could sell such interests; the actions of contractors; natural
disasters and adverse weather conditions; changes in public
expectations and other changes to business conditions; wars and
acts of terrorism; cyber-attacks or sabotage; and those factors
discussed under “Risk factors” in bp’s Annual
Report and Form 20-F for fiscal year 2025 as filed with the US
Securities and Exchange Commission.
Cautionary note
to U.S. investors - This document contains references to
non-proved reserves and production outlooks based on non-proved
reserves that the SEC’s rules prohibit us from including in
our filings with the SEC. U.S. investors are urged to consider
closely the disclosures in our Form 20-F, SEC File No. 1-06262.
This form is available on our website at www.bp.com. You can also
obtain this form from the SEC’s website at www.sec.gov.
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Contacts
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London
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Houston
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Press Office
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Rita Brown
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Paul Takahashi
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+44 (0) 7787 685821
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+1 713
903 9729
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Investor Relations
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Craig Marshall
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Graham Collins
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bp.com/investors
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+44 (0) 203 401 5592
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+1 832 753 5116
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BP
p.l.c.’s LEI Code 213800LH1BZH3DI6G760
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
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BP
p.l.c.
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(Registrant)
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Dated: 30
October 2026
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/s/
Alasdair Murray
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Alasdair
Murray
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Interim
Company Secretary
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